Table of Contents



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A10-K

(Amendment No. 1)

(Mark One)

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-31446

CIMAREX ENERGY CO.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

45-0466694
(I.R.S. Employer
Identification No.)

1700 Lincoln Street, Suite 3700, Denver, Colorado 80203

(Address of principal executive offices)

(303) 295-3995

(Registrant’s telephone number)

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class

each class

Name of each exchange on which registered

Common Stock ($0.01 par value)

New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES xý NO o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES oNO xý

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 xý NO o

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. xý

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

Large accelerated filer xý

Accelerated filer o

Non-accelerated filer o

(Do not check if a
smaller reporting company)

Smaller reporting company o

Emerging growth company o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES oNO xý

Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 20162018 was approximately $11.1$9.54 billion.

Number of shares of Cimarex Energy Co. common stock outstanding as of January 31, 20172019 was 95,121,492.

95,755,298.

Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 20172019 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.


Table of Contents

EXPLANATORY NOTE

Cimarex Energy Co. (together with its subsidiaries, “Cimarex,” the “company,” “our,” “we” or “us”) is filing this Amendment No. 1 (this “Form 10-K/A”) to amend its Annual Report on Form 10-K for the year ended December 31, 2016, originally filed with the Securities and Exchange Commission (the “SEC”) on February 24, 2017 (the “Original Filing”), to correct certain errors in our Consolidated Financial Statements included in Part II, Item 8 (collectively referred to as “Financial Statements”) and related footnote disclosures as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 (including the unaudited interim periods within 2016 and 2015). In connection with the corrections made in this Form 10-K/A, management reassessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 and concluded that a deficiency in the design of the company’s internal controls related to the full cost ceiling test calculation represents a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, 2016. In addition, this Form 10-K/A includes under Part II, Item 6 corrected selected financial data as of and for the years ended December 31, 2016 - 2012. This Form 10-K/A also amends certain other items in the Original Filing, as listed in “Items Amended in This Filing” below.

Background and Effects of Corrections

Subsequent to the filing of the Original Filing, in the course of preparing our consolidated financial statements for the quarter ended March 31, 2017, we identified an error in the quarterly ceiling test calculations used in prior periods to test our oil and gas properties for possible impairment. Specifically, the calculations did not properly consider the company’s tax net operating loss carryforwards in the calculation of the capitalized costs of net oil and gas properties to be tested for impairment. This error had the effect of incorrectly reporting impairment amounts in prior periods, which resulted in incorrectly reporting depletion expense and income tax expense (benefit) in prior periods.  Management promptly reported the matter to the Audit Committee of the company’s Board of Directors and KPMG LLP, the company’s independent registered public accounting firm.

After considering the guidance in SEC Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and Accounting Standards Codification 250, Accounting Changes and Error Corrections, we evaluated the materiality of the error on financial statement items quantitatively and qualitatively and concluded that the error was not material to any of the company’s prior annual or interim period financial statements. The consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and the unaudited interim period consolidated financial statements within the years ended December 31, 2016 and 2015 in this Form 10-K/A, have been revised in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements in order to reflect these corrections.  The corrections reflect the adjustments to impairment amounts, depletion expense and income tax expense (benefit) described above, as well as the resulting adjustments to deferred income taxes, accumulated depreciation, depletion and amortization and impairment, and retained earnings (accumulated deficit), including a cumulative catchup to the January 1, 2014 balance that gives effect to corrections made to the 2013 and 2012 periods.

In addition to correcting the consolidated financial statements, we have also corrected the Supplemental Quarterly Financial Data (Unaudited) and the following Notes to the consolidated financial statements for the effects of the errors discussed above:

· Note 1 — Basis of Presentation and Summary of Significant Accounting Policies

· Note 7 — Earnings (Loss) Per Share

· Note 9 — Income Taxes

The following tables present the effect of the corrections on selected line items of the previously reported consolidated financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014.

 

 

Consolidated Balance Sheet
December 31, 2016

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Accumulated depreciation, depletion and amortization and impairment

 

$

(13,849,701

)

$

(499,804

)

$

(14,349,505

)

Net oil and gas properties

 

$

2,854,071

 

$

(499,804

)

$

2,354,267

 

Total assets

 

$

4,681,693

 

$

(443,969

)

$

4,237,724

 

Deferred income tax (asset) liability

 

$

126,894

 

$

(182,729

)

$

(55,835

)

Total liabilities

 

$

2,321,629

 

$

(126,894

)

$

2,194,735

 

Retained earnings (accumulated deficit)

 

$

(405,284

)

$

(317,075

)

$

(722,359

)

Total stockholders’ equity

 

$

2,360,064

 

$

(317,075

)

$

2,042,989

 

Total liabilities and stockholders’ equity

 

$

4,681,693

 

$

(443,969

)

$

4,237,724

 

 

 

Consolidated Balance Sheet
December 31, 2015

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Accumulated depreciation, depletion and amortization and impairment

 

$

(12,710,968

)

$

(534,864

)

$

(13,245,832

)

Net oil and gas properties

 

$

3,276,146

 

$

(534,864

)

$

2,741,282

 

Total assets

 

$

5,243,286

 

$

(534,864

)

$

4,708,422

 

Deferred income tax (asset) liability

 

$

352,705

 

$

(195,543

)

$

157,162

 

Total liabilities

 

$

2,445,608

 

$

(195,543

)

$

2,250,065

 

Retained earnings (accumulated deficit)

 

$

33,313

 

$

(339,321

)

$

(306,008

)

Total stockholders’ equity

 

$

2,797,678

 

$

(339,321

)

$

2,458,357

 

Total liabilities and stockholders’ equity

 

$

5,243,286

 

$

(534,864

)

$

4,708,422

 

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Impairment of oil and gas properties

 

$

719,142

 

$

38,528

 

$

757,670

 

Depreciation, depletion and amortization

 

$

465,936

 

$

(73,588

)

$

392,348

 

Total operating expenses

 

$

1,864,292

 

$

(35,060

)

$

1,829,232

 

Operating income (loss)

 

$

(606,947

)

$

35,060

 

$

(571,887

)

Income (loss) before income tax

 

$

(658,264

)

$

35,060

 

$

(623,204

)

Income tax expense (benefit)

 

$

(227,215

)

$

12,814

 

$

(214,401

)

Net income (loss)

 

$

(431,049

)

$

22,246

 

$

(408,803

)

Total comprehensive income (loss)

 

$

(430,545

)

$

22,246

 

$

(408,299

)

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

 

 

$

0.32

 

Undistributed

 

(4.94

)

0.24

 

(4.70

)

 

 

$

(4.62

)

$

0.24

 

$

(4.38

)

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

 

 

$

0.32

 

Undistributed

 

(4.94

)

0.24

 

(4.70

)

 

 

$

(4.62

)

$

0.24

 

$

(4.38

)

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2015

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Impairment of oil and gas properties

 

$

3,716,883

 

$

316,412

 

$

4,033,295

 

Depreciation, depletion and amortization

 

$

778,923

 

$

(47,463

)

$

731,460

 

Total operating expenses

 

$

5,193,422

 

$

268,949

 

$

5,462,371

 

Operating income (loss)

 

$

(3,740,803

)

$

(268,949

)

$

(4,009,752

)

Income (loss) before income tax

 

$

(3,782,384

)

$

(268,949

)

$

(4,051,333

)

Income tax expense (benefit)

 

$

(1,373,436

)

$

(98,293

)

$

(1,471,729

)

Net income (loss)

 

$

(2,408,948

)

$

(170,656

)

$

(2,579,604

)

Total comprehensive income (loss)

 

$

(2,409,609

)

$

(170,656

)

$

(2,580,265

)

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

 0.64

 

Undistributed

 

(26.56

)

(1.83

)

(28.39

)

 

 

$

(25.92

)

$

 (1.83

)

$

 (27.75

)

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

(26.56

)

(1.83

)

(28.39

)

 

 

$

(25.92

)

$

 (1.83

)

$

(27.75

)

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2014

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Depreciation, depletion and amortization

 

$

806,021

 

$

(30,444

)

$

775,577

 

Total operating expenses

 

$

1,610,242

 

$

(30,444

)

$

1,579,798

 

Operating income (loss)

 

$

813,934

 

$

30,444

 

$

844,378

 

Income (loss) before income tax

 

$

805,901

 

$

30,444

 

$

836,345

 

Income tax expense (benefit)

 

$

298,697

 

$

11,150

 

$

309,847

 

Net income (loss)

 

$

507,204

 

$

19,294

 

$

526,498

 

Total comprehensive income (loss)

 

$

507,117

 

$

19,294

 

$

526,411

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

5.15

 

0.22

 

5.37

 

 

 

$

5.79

 

$

0.22

 

$

6.01

 

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

5.14

 

0.22

 

5.36

 

 

 

$

5.78

 

$

0.22

 

$

6.00

 

Correction of the errors discussed above impacted certain non-cash line items within the operating cash flow section of the consolidated statements of cash flows; however, the corrections did not change previously reported Net cash provided by operating activities for any period.

Internal Control Consideration

The Original Filing included a report of management’s assessment regarding internal control over financial reporting and an audit report of KPMG LLP, the company’s independent registered public accounting firm, without

qualifications. However, in connection with the corrections made in this Form 10-K/A, management re-evaluated the effectiveness of the company’s internal control over financial reporting as of December 31, 2016 and concluded that a deficiency in the design of the company’s internal controls related to the full cost ceiling test calculation represents a material weakness in the company’s internal control over financial reporting and, therefore, that the company did not maintain effective internal control over financial reporting as of December 31, 2016. This Form 10-K/A reflects this determination as of December 31, 2016 and the company’s independent registered public accounting firm, KPMG LLP, reissued its February 24, 2017 report on internal control over financial reporting as of December 31, 2016 to reflect an adverse opinion on the effectiveness of internal control over financial reporting due to the existence of a material weakness. For a description of the material weakness identified by management and the remediation efforts expected to be implemented to address that material weakness, see “Part II, Item 9A — Controls and Procedures.”

Items Amended in This Filing

For the convenience of the reader, this Form 10-K/A sets forth the Original Filing, in its entirety, as amended to reflect the corrections described above. No attempt has been made in this Form 10-K/A to update other disclosures presented in the Original Filing of our Annual Report on Form 10-K for the year ended December 31, 2016, except as required to reflect the effects of the corrections.

The following items have been amended as a result of corrections described above:

·                Part I — Cautionary Information about Forward-Looking Statements

·                Part I, Item 1A — Risk Factors

·                Part II, Item 6 — Selected Financial Data

·                  Part II, Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

·                Part II, Item 8 — Financial Statements and Supplementary Data

·                Part II, Item 9A — Controls and Procedures

The company’s Principal Executive Officer and Principal Financial Officer are providing currently dated certifications in connection with this Amended Annual Report on Form 10-K/A. These certifications are filed as Exhibits 31.1, 31.2, 32.1 and 32.2.



TABLE OF CONTENTS

DESCRIPTION

Item

 

Page

Glossary

 

 

 

Part I

 

1.& 2.

Business and Properties

10

1A.

Risk Factors

19

1B.

Unresolved Staff Comments

35

3.

Legal Proceedings

35

4.

Mine Safety Disclosures

35

 

Part II

 

5.

Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

36

6.

Selected Financial Data

38

7.

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

39

7A.

Quantitative and Qualitative Disclosures About Market Risk

64

8.

Financial Statements and Supplementary Data

65

9.

Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

116

9A.

Controls and Procedures

116

9B.

Other Information

119

 

Part III

 

10.

Directors, Executive Officers and Corporate Governance

120

11.

Executive Compensation

121

12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

121

13.

Certain Relationships and Related Transactions, and Director Independence

121

14.

Principal Accounting Fees and Services

122

 

Part IV

 

15.

Exhibits, Financial Statement Schedules

123

16.

Form 10-K Summary

127


Item  Page
Glossary
   
  
Part I
 
1. & 2.
 
Business and Properties
6
1A.
 
Risk Factors
15
1B.
 
Unresolved Staff Comments
33
3.
 
Legal Proceedings
33
4.
 
Mine Safety Disclosures
33
  
Part II
 
5.
 
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
34
6.
 
Selected Financial Data
36
7.
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
37
7A.
 
Quantitative and Qualitative Disclosures About Market Risk
61
8.
 
Financial Statements and Supplementary Data
62
9.
 
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
98
9A.
 
Controls and Procedures
98
9B.
 
Other Information
100
  
Part III
 
10.
 
Directors, Executive Officers and Corporate Governance
101
11.
 
Executive Compensation
102
12.
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
102
13.
 
Certain Relationships and Related Transactions, and Director Independence
102
14.
 
Principal Accounting Fees and Services
102
  
Part IV
 
15.
 
Exhibits, Financial Statement Schedules
103
16.
 
Form 10-K Summary
108


2

Table of Contents


GLOSSARY
GLOSSARYBbls—

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

BblsBcf——Barrels (of oil or natural gas liquids)

Bcf—Billion cubic feet

Bcfe—Billion cubic feet (of natural gas)

BOE—Barrels of oil equivalent

BtuGAAP——British thermal unit

GAAP—Generally accepted accounting principles in the U.S.

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

McfMBOE——Thousand barrels of oil equivalent
Mcf—Thousand cubic feet (of natural gas)

McfeMMBbls——Thousand cubic feet equivalent

MMBbl/MMBbls—Million barrels

MMBtuMMBtu——Million British thermal units

MMcfMMBOE——Million barrels of oil equivalent
MMcf—Million cubic feet

MMcf/d—Million cubic feet per day

MMcfe—Million cubic feet equivalent

MMcfe/d—Million cubic feet equivalent per day

Net Acres or Net Wells——Gross acreage multiplied byThe sum of the fractional working interest percentage

owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

Net ProductionProduction——Gross production multiplied by net revenue interest

NGL or NGLsNGLs——Natural gas liquids

PUDPUD——Proved undeveloped

TcfTcf——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.


3

Table of Contents


PART I

Cautionary Information about Forward-Looking Statements

CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
Throughout this Form 10-K/A,10-K, 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 Exchange Act of 1934. In particular, in our Management’s Discussion and Analysis of Financial Condition and Results of Operations, we are providing “2017 Outlook,” which containsprovide projections for certain 2017 operational activities.of our 2019 capital expenditures. All statements, other than statements of historical facts, that address activities, events, outcomes, and other matters that Cimarex plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates (and other similar expressions) will, should, or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10- K/A.10-K. Forward-looking statements include statements with respect to, among other things:

·

Fluctuations in the price we receive for our oil, gas, and NGL production;

·production, including local market price differentials;

Operating costs and other expenses;
Timing and amount of future production of oil, gas, and NGLs;

·

Reductions in the quantity of oil, gas, and NGLs sold and prices received due to decreased industrywide demand and/or curtailments in production from specific properties or areas due to mechanical, transportation, marketing, weather, or other problems;

·

Estimates of proved reserves, exploitation potential, or exploration prospect size;

·

Our ability to complete our pending acquisition of Resolute Energy Corporation (“Resolute”) and to successfully integrate the business of Resolute;
Our hedging activities and viability of hedge counterparties;
The effectiveness of our internal control over financial reporting;

·

Cash flow and anticipated liquidity;

·

Amount, nature, and timing of capital expenditures;

·                  Access

Availability of financing and access to capital markets;

·

Administrative, legislative, and regulatory changes;

·                  Operating costs and other expenses;

·

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;

·

Exploration and development opportunities that we pursue may not result in economic, productive oil and gas properties;

·

Drilling of wells;

·

Increased financing costs due to a significant increase in interest rates;

·                  De-risking

Proving up undeveloped acreage; and
Full cost ceiling test impairments to the carrying values of acreage;our oil and

·                  Our ability to remediate the identified material weakness in our internal control over financial reporting.

gas properties. 


4
Table of Contents


We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production, and sale of oil, gas, and NGLs.


These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production, andproduction type curves, well spacing, timing of development expenditures, and other risks described herein.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of such data by our engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the timing of future production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.


Risk factors related to our pending acquisition of Resolute include, among others: the expected timing and likelihood of completion of the proposed transaction, the ability to successfully integrate the businesses, the occurrence of any event, change, or other circumstances that could give rise to the termination of the merger agreement, the possibility that stockholders of Resolute may not approve the merger agreement, the risk that the parties may not be able to satisfy the conditions to the proposed transaction in a timely manner or at all, risks related to disruption of management time from ongoing business operations due to the proposed transaction, the risk that any announcements relating to the proposed transaction could have adverse effects on the market price of Cimarex’s common stock or Resolute’s common stock, the risk of any unexpected costs or expenses resulting from the proposed transaction, the outcome of any litigation relating to the proposed transaction, the risk that the proposed transaction and its announcement could have an adverse effect on the ability of Cimarex and Resolute to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally, the risk the pending proposed transaction could distract management of both entities and they will incur substantial fees and costs, the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or other anticipated benefits of the proposed transaction or it may take longer than expected to achieve those synergies or benefits and other important factors, such as expenses related to integration, that could cause actual results to differ materially from those projected. The acquisition is subject to an agreement and plan of merger entered into November 18, 2018 among the parties.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K/A10-K cause our underlying assumptions to be incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Form 10-K/A10-K and attributable to Cimarex are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Cimarex or persons acting on its behalf may issue. Cimarex does not undertake any obligation to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K/A10-K with the Securities and Exchange Commission, except as required by law.



5

Table of Contents


ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

Cimarex Energy Co., a Delaware corporation formed in 2002, is an independent oil and gas exploration and production company. Our operations are located mainly in Oklahoma, Texas, and New Mexico. On our website — www.cimarex.com — you will find our annual reports, proxy statements, and all of our Securities and Exchange Commission (SEC) filings.(“SEC”) filings, which we make available free of charge. Information contained on our website is not incorporated by reference into this Annual Report. Throughout this Form 10-K/A10-K we use the terms “Cimarex,” “company,” “we,” “our,” and “us” to refer to Cimarex Energy Co. and its subsidiaries.

Our principal business objective is to profitably growincrease shareholder value through the profitable long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the long-term benefit of our shareholders.long-term. Our strategy centers on maximizing cash flow from producing properties toso that we can reinvest in exploration and development opportunities.opportunities and provide cash returns to shareholders through increasing dividends. We consider merger and acquisition opportunities that enhance our competitive position and we occasionally divest non-core assets. Key elements to our approach include:

·

Maintain a strong financial position;

·                  Investment

Invest in a diversified portfolio of drilling opportunities;

·                  Rate-of-return driven evaluation

Evaluate projects based on rate-of-return and ranking ofrank investment decisions;

·                  Tracking

Track predicted versus actual results in a centralized exploration management system providingto provide feedback to improve results;

·                  Attracting

Attract quality employees and maintainingmaintain integrated teams of geoscientists, landmen, and engineers;

·                  Maximizing and

Maximize profitability.

Conservative use of leverage has long been the key to our financial strategy. We believe that low leverage coupled with strong full-cycle returns enables us to better withstand volatility in commodity prices and provide competitive returns and growth to shareholders. See Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Stock Performance Graph and Item 6 Selected Financial Data for additional financial and operating information for fiscal years 2012 — 2016.

2014 - 2018.

Proved Oil and Gas Reserves

Our December 31, 2018 total proved reserves were essentially flat in 2016.grew 6% from prior year-end. Proved undeveloped reserves as a percentage of total proved reserves decreased to 21%15% from 25%17% a year ago. We added 324.0 Bcfe158.5 MMBOE of new reserves through extensions and discoveries and 126.2 Bcfe through net positive performancediscoveries. Net negative revisions replacing 128%totaled 22.7 MMBOE, which consisted primarily of production.a decrease of 38.6 MMBOE for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, partially offset by an increase of 20.9 MMBOE for technical revisions. The change in our proved reserves is as follows (in Bcfe):

follows:

Proved Reserves
(MBOE)
Reserves at December 31, 2015

2017

559,037

2,909.4


Revisions of previous estimates

(22,667

19.8

)

Extensions and discoveries

158,512

324.0


Purchases of reserves

1

0.9


Production

(81,010

(352.6

)

Sales of reserves

(22,678

(11.0

)

Reserves at December 31, 2016

2018

591,195

2,890.5



6

RevisionsTable of previous estimates in the above table include net positive performance and operating cost related revisions of 126.2 Bcfe and 138.5 Bcfe, respectively, partially offset by negative commodity price revisions of 244.9 Bcfe.

Contents



A breakdown by commodity of our proved oil and gas reserves follows:

 

 

December 31,

 

 

 

2016

 

2015

 

2014

 

Total Proved Reserves:

 

 

 

 

 

 

 

Gas (Bcf)

 

1,471.4

 

1,517.0

 

1,666.7

 

Oil (MMBbls)

 

105.9

 

107.8

 

119.0

 

NGL (MMBbls)

 

130.6

 

124.3

 

125.3

 

Equivalent (Bcfe)

 

2,890.5

 

2,909.4

 

3,132.3

 

% Developed

 

79

 

75

 

77

 

 December 31,
 2018 2017 2016
Proved reserves: 
  
  
Gas (MMcf)1,591,321
 1,607,635
 1,471,420
Oil (MBbls)146,538
 137,238
 105,878
NGL (MBbls)179,436
 153,860
 130,633
Total (MBOE)591,195
 559,037
 481,748
Percent developed85% 83% 79%
The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2018.
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
 
% of
Total Proved
Reserves
Mid-Continent861,440
 29,908
 82,826
 256,307
 43%
Permian Basin727,985
 116,378
 96,533
 334,241
 57%
Other1,896
 252
 77
 647
 —%
 1,591,321
 146,538
 179,436
 591,195
 100%
See “Supplemental Oil and Gas Information”SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 of this report for further information.

information regarding our reserves.


7
Table of Contents


Production Volumes, Prices, and Costs


All of our oil and gas assets are located in the United States. We have varying levels of ownership interests in our properties consisting of working, royalty, and overriding royalty interests. Operated wells account for approximately 83% of our proved reserves.

Our 20162018 production volumes totaled 963 MMcfe221.9 MBOE per day, a 2% decrease17% increase from 2015,2017, and were comprised of 48% natural42% gas, 28%31% oil, and 24%27% NGLs. The following tables showtable presents our total and average daily production volumes by region,region.
  Total Production Volumes Average Daily Production Volumes
Years Ended 
December 31,
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
2018  
  
  
  
  
  
  
  
Permian Basin 92,593
 19,104
 11,499
 46,035
 253.7
 52.3
 31.5
 126.1
Mid-Continent 112,697
 5,530
 10,474
 34,787
 308.8
 15.2
 28.7
 95.3
Other 547
 76
 21
 188
 1.4
 0.2
 0.1
 0.5
Total company 205,837
 24,710
 21,994
 81,010
 563.9
 67.7
 60.3
 221.9
                 
2017  
  
  
  
  
  
  
  
Permian Basin 79,521
 16,271
 8,858
 38,382
 217.9
 44.6
 24.3
 105.2
Mid-Continent 107,463
 4,547
 8,503
 30,960
 294.4
 12.5
 23.3
 84.8
Other 484
 43
 13
 137
 1.3
 0.1
 —
 0.4
Total company 187,468
 20,861
 17,374
 69,479
 513.6
 57.2
 47.6
 190.4
                 
2016  
  
  
  
  
  
  
  
Permian Basin 65,191
 13,183
 6,677
 30,725
 178.1
 36.0
 18.2
 83.9
Mid-Continent 102,501
 3,283
 7,508
 27,874
 280.1
 9.0
 20.5
 76.2
Other 535
 62
 15
 166
 1.4
 0.2
 0.1
 0.5
Total company 168,227
 16,528
 14,200
 58,765
 459.6
 45.2
 38.8
 160.6

At December 31, 2018, we had two fields that contained 15% or more of our total proved reserves. These fields are the Watonga-Chickasha in the Cana area of the Mid-Continent, which contained approximately 39% of our total proved reserves, and the Ford West in the Permian Basin, which contained approximately 16% of our total proved reserves. At December 31, 2017 and 2016, the Watonga-Chickasha was our only field that contained 15% or more of our total proved reserves. Production for these fields is presented in the following table.

  Total Production Volumes Average Daily Production Volumes
Years Ended December 31, 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
2018  
  
  
  
  
  
  
  
Watonga-Chickasha 96,373
 5,094
 9,774
 30,930
 264.0
 14.0
 26.8
 84.7
Ford West 30,958
 3,748
 3,804
 12,711
 84.8
 10.3
 10.4
 34.8
                 
2017                
Watonga-Chickasha 88,557
 4,156
 7,829
 26,744
 242.6
 11.4
 21.4
 73.3
Ford West 26,405
 3,370
 2,883
 10,654
 72.3
 9.2
 7.9
 29.2
                 
2016                
Watonga-Chickasha 81,757
 2,823
 6,764
 23,213
 223.4
 7.7
 18.5
 63.4
Ford West 20,034
 2,258
 1,927
 7,525
 54.7
 6.2
 5.3
 20.6


8
Table of Contents


The following table presents the average commodity prices received and production cost per unit of production.  Separate data is also included for the Cana area, which comprises the majority of the production of our largest producing field, the Watonga-Chickasha in western Oklahoma.

 

 

Production Volumes

 

Net Average Daily Volumes

 

 

 

Gas

 

Oil

 

NGL

 

Total

 

Gas

 

Oil

 

NGL

 

Total

 

Years Ended December 31,

 

(MMcf)

 

(MBbls)

 

(MBbls)

 

(MMcfe)

 

(MMcf)

 

(MBbls)

 

(MBbls)

 

(MMcfe)

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

65,191

 

13,183

 

6,677

 

184,351

 

178.1

 

36.0

 

18.2

 

503.7

 

Mid-Continent

 

102,501

 

3,283

 

7,508

 

167,243

 

280.1

 

9.0

 

20.5

 

456.9

 

Other

 

535

 

62

 

15

 

997

 

1.4

 

0.2

 

0.1

 

2.8

 

Total Company

 

168,227

 

16,528

 

14,200

 

352,591

 

459.6

 

45.2

 

38.8

 

963.4

 

Cana area

 

82,423

 

2,848

 

6,855

 

140,647

 

225.2

 

7.8

 

18.7

 

384.3

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

66,006

 

15,719

 

6,220

 

197,644

 

180.8

 

43.1

 

17.0

 

541.5

 

Mid-Continent

 

100,801

 

2,746

 

6,757

 

157,821

 

276.2

 

7.5

 

18.5

 

432.4

 

Other

 

2,180

 

198

 

86

 

3,878

 

6.0

 

0.5

 

0.3

 

10.6

 

Total Company

 

168,987

 

18,663

 

13,063

 

359,343

 

463.0

 

51.1

 

35.8

 

984.5

 

Cana area

 

77,882

 

2,206

 

5,957

 

126,865

 

213.4

 

6.0

 

16.3

 

347.6

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

45,200

 

12,552

 

4,187

 

145,636

 

123.8

 

34.4

 

11.5

 

399.0

 

Mid-Continent

 

106,711

 

2,682

 

6,980

 

164,682

 

292.4

 

7.3

 

19.1

 

451.2

 

Other

 

3,217

 

405

 

176

 

6,704

 

8.8

 

1.1

 

0.5

 

18.4

 

Total Company

 

155,128

 

15,639

 

11,343

 

317,022

 

425.0

 

42.8

 

31.1

 

868.6

 

Cana area

 

76,915

 

1,903

 

5,937

 

123,952

 

210.7

 

5.2

 

16.3

 

339.6

 

 

 

Average Realized Price

 

Production

 

 

 

Gas

 

Oil

 

NGL

 

Cost

 

Years Ended December 31,

 

(per Mcf)

 

(per Bbl)

 

(per Bbl)

 

(per Mcfe)

 

2016

 

 

 

 

 

 

 

 

 

Permian Basin

 

$

2.35

 

$

38.45

 

$

12.32

 

$

0.86

 

Mid-Continent

 

$

2.29

 

$

37.65

 

$

15.59

 

$

0.43

 

Other

 

$

2.00

 

$

38.86

 

$

14.80

 

$

1.59

 

Total Company

 

$

2.31

 

$

38.30

 

$

14.05

 

$

0.66

 

Cana area

 

$

2.28

 

$

37.73

 

$

15.80

 

$

0.23

 

2015

 

 

 

 

 

 

 

 

 

Permian Basin

 

$

2.55

 

$

43.58

 

$

11.94

 

$

1.06

 

Mid-Continent

 

$

2.51

 

$

41.90

 

$

15.41

 

$

0.52

 

Other

 

$

3.16

 

$

48.01

 

$

14.72

 

$

1.72

 

Total Company

 

$

2.53

 

$

43.38

 

$

13.75

 

$

0.83

 

Cana area

 

$

2.51

 

$

41.54

 

$

15.59

 

$

0.26

 

2014

 

 

 

 

 

 

 

 

 

Permian Basin

 

$

4.48

 

$

82.44

 

$

30.04

 

$

1.58

 

Mid-Continent

 

$

4.42

 

$

88.23

 

$

35.03

 

$

0.58

 

Other

 

$

4.40

 

$

92.82

 

$

32.09

 

$

2.31

 

Total Company

 

$

4.43

 

$

83.70

 

$

33.14

 

$

1.08

 

Cana area

 

$

4.32

 

$

88.21

 

$

34.89

 

$

0.24

 

by region.


  Average Realized Price Production Cost (per BOE)
Years Ended December 31, 
Gas
(per Mcf)
 
Oil
(per Bbl)
 
NGL
(per Bbl)
 
2018  
  
  
  
Permian Basin $1.69
 $54.95
 $22.84
 $4.30
Mid-Continent $2.23
 $62.31
 $21.67
 $2.69
Other $2.97
 $58.40
 $26.46
 $7.63
Total Company $1.99
 $56.61
 $22.28
 $3.62
         
2017  
  
  
  
Permian Basin $2.72
 $46.96
 $20.25
 $4.70
Mid-Continent $2.78
 $47.42
 $23.02
 $2.60
Other $2.74
 $46.53
 $23.11
 $9.03
Total Company $2.76
 $47.06
 $21.61
 $3.77
         
2016  
  
  
  
Permian Basin $2.35
 $38.45
 $12.32
 $5.16
Mid-Continent $2.29
 $37.65
 $15.59
 $2.57
Other $2.00
 $38.86
 $14.80
 $9.56
Total Company $2.31
 $38.30
 $14.05
 $3.95
Acquisitions and Divestitures

We consider property acquisitions, divestitures, and occasional mergers to enhance our competitive position. Moreover, sales of non-core assets are a source of liquidity that we can use to supplement funding of capital expenditures and acquisitions of core assets.

In 20162018, we sold interests in various non-core oil and gas properties for $21cash proceeds totaling $581 million. Included in these divestitures was a sale of oil and gas properties principally located in Ward County, Texas for which we have received, as of December 31, 2018, $534.6 million andin net cash proceeds. Final settlement, which will reflect customary post-closing adjustments, is scheduled to occur by the end of first quarter 2019.

In 2018, we made various oil and gas property acquisitions totaling $11for $26 million.

Additionally, we entered into an agreement and plan of merger to acquire Resolute in a cash and stock transaction valued at a total purchase price of approximately $1.6 billion, including cash, stock, and the assumption of Resolute’s long-term debt. This pending acquisition will expand our footprint in Reeves County, Texas by 21,100 net acres that are complementary to our existing Reeves County position. The transaction, which is expected to be completed by the end of the first quarter 2019, is subject to the approval of Resolute shareholders and the satisfaction of certain regulatory approvals and other customary closing conditions.


Exploration and Development Overview

Cimarex has one reportable segment, exploration and production (E&P)(“E&P”). Our E&P activities take place primarily in two areas: the Permian Basin and the Mid-Continent region. Almost all of our exploration and development (E&D)(“E&D”) capital is allocated between these two areas.  In 2016, E&D investment totaled $735 million.  Of that, 59% was invested in the Permian Basin and 40% in the Mid-Continent region.

In 2016, Cimarex drilled or participated in 154 gross (61.0 net) wells,



9
Table of which we operated 73 gross (51.2 net) wells.  At year-end, we were in the process of drilling or participating in 19 gross (8.4 net) wells and there were 93 gross (27.0 net) wells waiting on completion.  Contents


regionmap.jpg
A summary of our 20162018 exploration and development activity by region is as follows:

 

 

 

 

Gross

 

Net

 

%

 

 

 

E&D

 

Wells

 

Wells

 

Completed

 

 

 

Capital

 

Drilled

 

Drilled

 

As Producers

 

 

 

(in millions)

 

 

 

 

 

 

 

Permian Basin

 

$

433

 

48

 

30.3

 

100

 

Mid-Continent

 

291

 

106

 

30.7

 

99

 

Other

 

11

 

—

 

—

 

—

 

 

 

$

735

 

154

 

61.0

 

99

 

 
E&D
Capital
 
Gross
Wells
Completed
 
Net
Wells
Completed
 
%
Completed
As Producers
 (in millions)      
Permian Basin$1,092
 129
 79.9
 100%
Mid-Continent472
 220
 42.2
 100%
Other6
 —
 —
 —%
 $1,570
 349
 122.1
 100%
The Permian regionBasin encompasses west Texas and southeast New Mexico. Cimarex’s Permian Basin efforts are located in the western half of the Permian Basin known as the Delaware Basin. In 2016,2018, we focused on drilling horizontal wells that yielded oil and liquids-rich gas from the Wolfcamp shale and the Bone Spring formation. Cimarex saw improved results in its Wolfcamp shale wells, as measured by production and reserves, with the further implementation of long laterals and continued improvement in well completion design and in the Bone Spring wells via upsizedlarger well completions.

The Permian regionBasin produced 504 MMcfe126.1 MBOE per day in 2016,2018, which was 52%57% of our total company production. Total production from the region decreased 7%increased 20% in 20162018 over 2015.

2017. In 2018, we invested $1.09 billion, or 70% of our total E&D investment, in the Permian Basin.

Our Mid-Continent region consists of Oklahoma and the Texas Panhandle. Our activity in 20162018 in the Mid-Continent was focused in the Woodford shale and the Meramec horizon, both in Oklahoma. We continued to implement largerrefine well completions and spacing in the Woodford shale and we applied those same techniques to delineate the Meramec horizon, located above the Woodford.  Cimarex continues to evaluate the size and potential of the Meramec play.

horizon.

During 2016,2018, production from the Mid-Continent averaged 457 MMcfe95.3 MBOE per day, or 47%43% of total company production. Total production from the region increased 6%12% in 20162018 over 2015.

2017. In 2018, we invested $472 million, or 30% of our total E&D investment, in the Mid-Continent.

Drilling Activity

In 2018, we completed or participated in the completion of 349 gross (122.1 net) wells, of which we operated 146 gross (105.8 net) wells. At year-end, we were in the process of drilling or participating in 40 gross (12.6 net) wells and there were 83 gross (28.3 net) wells waiting on completion.

10
Table of Contents


We completed the following number of exploratory and developmental wells in the years indicated:

 

 

Wells Completed

 

 

 

2016

 

2015

 

2014

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Exploratory

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

—

 

—

 

—

 

—

 

1

 

0.4

 

Dry

 

—

 

—

 

—

 

—

 

1

 

0.5

 

Total

 

—

 

—

 

—

 

—

 

2

 

0.9

 

Developmental

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

153

 

61.0

 

219

 

98.7

 

309

 

173.6

 

Dry

 

1

 

—

 

3

 

1.7

 

1

 

0.1

 

Total

 

154

 

61.0

 

222

 

100.4

 

310

 

173.7

 

indicated in the table below. During these years, we completed no exploratory wells.

 Wells Completed
 2018 2017 2016
 Gross Net Gross Net Gross Net
Developmental 
  
  
  
  
  
Productive349
 122.1
 314
 96.4
 153
 61.0
Dry—
 —
 5
 1.6
 1
 —
Total349
 122.1
 319
 98.0
 154
 61.0
At December 31, 2018, we owned an interest in 10,362 gross (2,902 net) productive oil and gas wells. We havehad working interests in the following number of productive wells by region as of December 31, 2016:

 

 

Gas

 

Oil

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Mid-Continent

 

3,831

 

1,480

 

531

 

166

 

Permian Basin

 

831

 

406

 

4,967

 

1,029

 

Other

 

100

 

9

 

19

 

4

 

 

 

4,762

 

1,895

 

5,517

 

1,199

 

Significant Properties

All2018:

 Gas Oil
 Gross Net Gross Net
Mid-Continent3,992
 1,513
 791
 197
Permian Basin769
 342
 4,702
 842
Other93
 6
 15
 2
 4,854
 1,861
 5,508
 1,041


11
Table of our oil and gas assets are located in the United States.  We have varying levels of ownership interests in our properties consisting of working, royalty and overriding royalty interests.  Operated wells account for 76% of our proved reserves.  In 2016, proved reserves in the Cana area of the Watonga-Chickasha field were approximately 57% of Cimarex’s total proved reserves.  No other field had reserves in excess of 15% of our total proved reserves.

At December 31, 2016, 63% of our total proved reserves were located in the Mid-Continent region and 37% were in the Permian Basin.  We owned an interest in 10,279 gross (3,094 net) productive oil and gas wells.  The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2016.

 

 

 

 

 

 

 

 

 

 

% of

 

 

 

Gas

 

Oil

 

NGL

 

Total

 

Total Proved

 

 

 

(Bcf)

 

(MMBbl)

 

(MMBbl)

 

(Bcfe)

 

Reserves

 

Mid-Continent

 

1,095.2

 

31.4

 

89.6

 

1,821.3

 

63

 

Permian Basin

 

372.4

 

74.3

 

41.0

 

1,064.0

 

37

 

Other

 

3.8

 

0.2

 

—

 

5.2

 

—

 

 

 

1,471.4

 

105.9

 

130.6

 

2,890.5

 

100

 

Contents

At December 31, 2016, our ten largest producing fields held 86% of total proved reserves.  We are the principal operator of our production in each of these fields.

 

 

 

 

% of

 

 

 

 

 

 

 

 

 

 

 

Total

 

Average

 

Approximate

 

 

 

 

 

 

 

Proved

 

Working

 

Average Depth

 

 

 

Field

 

Region

 

Reserves

 

Interest%

 

(feet)

 

Primary Formation

 

 

 

 

 

 

 

 

 

 

 

 

 

Watonga-Chickasha

 

Mid-Continent

 

57.1

 

34.1

 

13,000'

 

Woodford

 

Ford, West

 

Permian Basin

 

8.4

 

56.9

 

9,500'

 

Wolfcamp

 

Dixieland

 

Permian Basin

 

6.1

 

96.8

 

11,000'

 

Wolfcamp

 

Lusk

 

Permian Basin

 

3.9

 

54.8

 

9,500'

 

Bone Spring

 

Cottonwood Draw

 

Permian Basin

 

2.6

 

73.7

 

3,000' - 10,000'

 

Delaware/Wolfcamp

 

Grisham

 

Permian Basin

 

1.8

 

100.0

 

11,000'

 

Wolfcamp

 

Phantom

 

Permian Basin

 

1.7

 

57.5

 

11,500'

 

Bone Spring

 

Two Georges

 

Permian Basin

 

1.7

 

90.5

 

11,500'

 

Bone Spring

 

Sandbar

 

Permian Basin

 

1.4

 

58.8

 

7,500'

 

Bone Spring

 

Quail Ridge

 

Permian Basin

 

1.0

 

36.5

 

8,000' - 13,000'

 

Bone Spring/Morrow

 

 

 

 

 

85.7

 

 

 

 

 

 

 



Acreage

The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of December 31, 2016.2018. Gross acres are the total number of acres in which we own a working interest. Net acres are the gross acres multiplied by our working interest.

 

 

Acreage

 

 

 

Undeveloped

 

Developed

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Mid-Continent

 

 

 

 

 

 

 

 

 

 

 

 

 

Kansas

 

18,231

 

18,191

 

—

 

—

 

18,231

 

18,191

 

Oklahoma

 

107,015

 

71,658

 

686,489

 

295,176

 

793,504

 

366,834

 

Texas

 

22,045

 

11,301

 

133,839

 

56,708

 

155,884

 

68,009

 

 

 

147,291

 

101,150

 

820,328

 

351,884

 

967,619

 

453,034

 

Permian Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

New Mexico

 

73,882

 

52,669

 

175,842

 

119,597

 

249,724

 

172,266

 

Texas

 

81,443

 

63,289

 

201,078

 

147,829

 

282,521

 

211,118

 

 

 

155,325

 

115,958

 

376,920

 

267,426

 

532,245

 

383,384

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

Arizona

 

2,097,201

 

2,097,201

 

17,847

 

—

 

2,115,048

 

2,097,201

 

California

 

383,647

 

383,647

 

—

 

—

 

383,647

 

383,647

 

Colorado

 

41,992

 

18,867

 

40,800

 

1,642

 

82,792

 

20,509

 

Gulf of Mexico

 

25,000

 

13,000

 

28,848

 

6,381

 

53,848

 

19,381

 

Louisiana

 

3,533

 

484

 

2,877

 

170

 

6,410

 

654

 

Michigan

 

26,491

 

26,414

 

1,183

 

1,183

 

27,674

 

27,597

 

Montana

 

34,381

 

9,167

 

7,688

 

1,721

 

42,069

 

10,888

 

Nevada

 

1,007,167

 

1,007,167

 

440

 

1

 

1,007,607

 

1,007,168

 

New Mexico

 

1,641,206

 

1,633,821

 

18,371

 

2,436

 

1,659,577

 

1,636,257

 

Texas

 

10,478

 

3,724

 

27,174

 

6,167

 

37,652

 

9,891

 

Utah

 

80,527

 

59,433

 

32,552

 

1,575

 

113,079

 

61,008

 

Wyoming

 

97,157

 

13,744

 

43,626

 

4,197

 

140,783

 

17,941

 

Other

 

194,398

 

171,229

 

9,734

 

3,460

 

204,132

 

174,689

 

 

 

5,643,178

 

5,437,898

 

231,140

 

28,933

 

5,874,318

 

5,466,831

 

Total

 

5,945,794

 

5,655,006

 

1,428,388

 

648,243

 

7,374,182

 

6,303,249

 

 Acreage
 Undeveloped Developed Total
 Gross Net Gross Net Gross Net
Mid-Continent 
  
  
  
  
  
Kansas18,231
 18,191
 —
 —
 18,231
 18,191
Oklahoma97,203
 65,250
 687,246
 305,702
 784,449
 370,952
Texas17,975
 12,302
 128,956
 54,255
 146,931
 66,557
 133,409
 95,743
 816,202
 359,957
 949,611
 455,700
Permian Basin 
  
  
  
  
  
New Mexico74,227
 54,657
 175,974
 119,892
 250,201
 174,549
Texas69,566
 50,852
 182,717
 121,933
 252,283
 172,785
 143,793
 105,509
 358,691
 241,825
 502,484
 347,334
Other 
  
  
  
  
  
Arizona2,097,841
 2,097,841
 17,207
 —
 2,115,048
 2,097,841
California383,487
 383,487
 —
 —
 383,487
 383,487
Colorado40,232
 18,867
 41,384
 1,642
 81,616
 20,509
Gulf of Mexico25,000
 13,000
 28,848
 6,381
 53,848
 19,381
Louisiana132,842
 129,792
 2,868
 168
 135,710
 129,960
Michigan234
 156
 587
 587
 821
 743
Montana30,755
 7,687
 7,688
 1,721
 38,443
 9,408
Nevada1,007,167
 1,007,167
 440
 1
 1,007,607
 1,007,168
New Mexico1,641,126
 1,633,819
 18,331
 2,436
 1,659,457
 1,636,255
Texas8,888
 2,696
 23,549
 4,784
 32,437
 7,480
Utah80,527
 59,433
 31,912
 1,495
 112,439
 60,928
Wyoming96,454
 13,944
 41,629
 3,829
 138,083
 17,773
Other168,034
 145,680
 9,627
 3,351
 177,661
 149,031
 5,712,587
 5,513,569
 224,070
 26,395
 5,936,657
 5,539,964
Total5,989,789
 5,714,821
 1,398,963
 628,177
 7,388,752
 6,342,998
The table below summarizes by year and region our undeveloped acreage expirations in the next five years. In most cases, the drilling of a commercial well will hold the acreage beyond the expiration.

 

 

Acreage

 

 

 

2017

 

2018

 

2019

 

2020

 

2021

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Mid-Continent

 

22,804

 

18,383

 

11,288

 

6,462

 

1,695

 

1,525

 

—

 

—

 

—

 

—

 

Permian Basin

 

17,025

 

17,005

 

5,527

 

5,527

 

8,360

 

8,198

 

40

 

40

 

598

 

598

 

Other

 

51,036

 

50,281

 

30,709

 

29,992

 

63,334

 

59,092

 

28,867

 

28,652

 

7,042

 

6,953

 

 

 

90,865

 

85,669

 

47,524

 

41,981

 

73,389

 

68,815

 

28,907

 

28,692

 

7,640

 

7,551

 

% of undeveloped acreage

 

1.5

 

1.5

 

0.8

 

0.7

 

1.2

 

1.2

 

0.5

 

0.5

 

0.1

 

0.1

 

 Acreage
 2019 2020 2021 2022 2023
 Gross Net Gross Net Gross Net Gross Net Gross Net
Mid-Continent1,940
 1,543
 10,942
 10,923
 6,682
 6,682
 1,848
 1,848
 284
 284
Permian Basin15,224
 15,224
 10,154
 10,154
 4,290
 4,290
 2,148
 2,148
 960
 960
Other180,509
 176,413
 34,934
 34,901
 10,706
 10,626
 31,961
 30,940
 7,105
 6,963
 197,673
 193,180
 56,030
 55,978
 21,678
 21,598
 35,957
 34,936
 8,349
 8,207
                    
% of undeveloped acreage3.3
 3.4
 0.9
 1.0
 0.4
 0.4
 0.6
 0.6
 0.1
 0.1
At December 31, 2016,2018, we had no proved undeveloped reserves associated with expiringscheduled for development beyond the expiration dates of our undeveloped acreage.


12
Table of Contents


Marketing

Our oil and gas production is sold under short-term arrangements at market-responsive prices. We sell our oil at prices tied directly or indirectly to field postings. Our gas is sold under price mechanisms related to either monthly or daily index prices on pipelines where we deliver our gas.

We sell our NGLs at prices tied to monthly index prices where we deliver our NGLs.

We sell our oil, gas, and gasNGLs to a broad portfolio of customers.  Ourcustomers, including major customer during 2016 was Sunoco Logistics Partners L.P. (Sunoco), which accounted for 20%energy companies, pipeline companies, local distribution companies, and other end-users. In 2018, we made sales to two customers that each amounted to 10% or more of our consolidated revenues for the year.

2018. Sales to those two customers accounted for 23% and 21%, respectively, of our consolidated revenues for 2018. If Sunocoany one of our major customers were to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our product,production, we believe there would be challenges initially, but ample markets to handle the disruption.

We regularly monitor the credit worthiness of all our customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.

Historically, losses associated with uncollectible receivables have not been significant.

Corporate Headquarters and Employees

Our corporate headquarters is located at 1700 Lincoln St., Suite 3700, Denver, Colorado 80203. On December 31, 20162018 and 2015,2017, Cimarex had 856955 and 925910 employees, respectively. None of our employees are subject to collective bargaining agreements.

Competition

The oil and gas industry is highly competitive, particularly for prospective undeveloped leases and purchases of proved reserves. There is also competition for rigs and related equipment used to drill for and produce oil and gas, however, to a lesser extent in the current market environment. Our competitive position also is also highly dependent on our ability to recruit and retain geological, geophysical, and engineering expertise. We compete for prospects, proved reserves, oil-field services, and qualified oil and gas professionals with major and diversified energy companies and other independent operators that have larger financial, human, and technological resources than we do.

We compete with integrated, independent, and other energy companies for the sale and transportation of our oil, gas, and NGLs to marketing companies and end users. The oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial, and residential consumers. Many of these competitors have greater financial and human resources. The effect of these competitive factors cannot be predicted.

Proved Reserves Estimation Procedures

Proved oil and gas reserve quantities are based on estimates prepared by Cimarex in accordance with the SEC’s rules for reporting oil and gas reserves. Our reserve definitions conform with definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the SEC. All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians. The objectives and management of this group are separate from and independent of the exploration and production functions of the company. The primary objective of our Corporate Reservoir Engineering group is to maintain accurate forecasts on all properties of the company through ongoing monitoring and timely updates of operating and economic parameters (production forecasts, prices and regional differentials, operating expenses, ownership, etc.) in accordance with guidelines established by the SEC. This separation of function and responsibility is a key internal control.

Cimarex engineers are responsible for estimates of proved reserves. Corporate engineers interact with the exploration and production departments to ensure all available engineering and geologic data is taken into account prior to establishing or revising an estimate. After preparing the reserves update, the corporate engineers review their recommendations with the Vice President of Corporate Engineering. After approval from the Vice President of Corporate Engineering, the revisions are entered into our reserves database by the engineering technician.


13
Table of Contents


During the course of the year, the Vice President of Corporate Engineering presents summary reserves information to senior management and to our Board of Directors for their review. From time to time, the Vice President of Corporate Engineering also will confer with the Vice President of Exploration, Chief Operating Officer, and the Chief Executive Officer regarding specific reserves-related issues. In addition, Corporate Reservoir Engineering maintains a set of basic guidelines and procedures to ensure that critical checks and reviews of the reserves database are performed on a regular basis.

Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewedperformed an independent evaluation of our estimated net reserves associated withrepresenting greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2016.2018. The individual primarily responsible for overseeing the review is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3734 years of experience in oil and gas reservoir studies and reserves evaluations.

The technical employee primarily responsible for overseeing the oil and gas reserves estimation process is Cimarex’s Vice President of Corporate Engineering. This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than 2224 years of practical experience in oil and gas reservoir evaluation. He has been directly involved in the annual reserves reporting process of Cimarex since 2002 and has served in his current role for the past 1214 years.

Title to Oil and Gas Properties

We undertake title examination and perform curative work at the time we lease undeveloped acreage, prepare for the drilling of a prospect, or acquire proved properties. We believe title to our properties is good and defensible, and is in accordance with industry standards. Nevertheless, we are involved in title disputes from time to time that result in litigation. Our oil and gas properties are subject to customary royalty interests, liens incidental to operating agreements, tax liens, and other burdens and minor encumbrances, easements, and restrictions.

Government Regulation

Oil and gas production and transportation is subject to extensive federal, state, and local laws and regulations. Compliance with existing laws often is difficult and costly, but has not had a significant adverse effect on our operations or financial condition. In recent years, we have been most directly impacted by federal and state environmental regulations and energy conservation rules. We are also impacted by federal and state regulation of pipelines and other oil and gas transportation systems.

The states in which we conduct operations establish requirements for drilling permits, the method of developing fields, the size of well spacing units, drilling density within productive formations and the unitization or pooling of properties. In addition, state conservation laws include requirements for waste prevention, establish limits on the maximum rate of production from wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production.

Environmental Regulation.Various federal, state, and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development, and production operations, which consequently impact our operations and costs. These laws and regulations govern, among other things, emissions into the atmosphere, discharges of pollutants into waters, underground injection of waste water, the generation, storage, transportation, and disposal of waste materials, and protection of public health, natural resources, and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

Cimarex is committed to environmental protection and believes we are in material compliance with applicable environmental laws and regulations. We obtain permits for our facilities and operations in accordance with the applicable laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations. Expenditures are required to comply with environmental regulations. These costs are a normal, recurring expense of operations and not an extraordinary cost of compliance with current government regulations.


14
Table of Contents


We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our financial position or operations. However, due to continuing changes in these laws and regulations, we are unable to predict with any reasonable degree of certainty any potential delays in development plans that could arise, or our future costs of complying with governmental requirements. We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, produced water, or other substances as well as additional coverage for certain other pollution events.

Gas Gathering and Transportation.The Federal Energy Regulatory Commission (FERC)(“FERC”) requires interstate gas pipelines to provide open access transportation. FERC also enforces the prohibition of market manipulation by any entity, and the facilitation of the sale or transportation of natural gas in interstate commerce. Interstate pipelines have implemented these requirements, providing us with additional market access and more fairly applied transportation services and rates. FERC continues to review and modify its open access and other regulations applicable to interstate pipelines.

Under the Natural Gas Policy Act (NGPA)(“NGPA”), natural gas gathering facilities are expressly exempt from FERC jurisdiction. What constitutes “gathering” under the NGPA has evolved through FERC decisions and judicial review of such decisions. We believe that our gathering systems meet the test for non-jurisdictional “gathering” systems under the NGPA and that our facilities are not subject to federal regulations. Although exempt from FERC oversight, our natural gas gathering systems and services may receive regulatory scrutiny by state and federal agencies regarding the safety and operating aspects of the transportation and storage activities of these facilities.

In addition to using our own gathering facilities, we may use third-party gathering services or interstate transmission facilities (owned and operated by interstate pipelines) to ship our gas to markets.

Additional proposals and proceedings that might affect the oil and gas industry are pending before the U.S. Congress, FERC, Bureau of Land Management (BLM)(“BLM”), U.S. Environmental Protection Agency (EPA)(“EPA”), state legislatures, state agencies, local governments, and the courts. We cannot predict when or whether any such proposals may become effective and what effect they will have on our operations. We do not anticipate that compliance with existing federal, state, and local laws, rules, or regulations will have a material adverse effect upon our capital expenditures, earnings, or competitive position.

Federal and State Income and Other Local Taxation

Cimarex and the petroleum industry in general are affected by both federal and state income tax laws, as well as other local tax regulations involving ad valorem, personal property, franchise, severance, and other excise taxes. We have considered the effects of these provisions on our operations and do not anticipate that there will be any material undisclosed impact on our capital expenditures, earnings, or competitive position.

Executive Officers of the Registrant

See Part III, Item 10, Directors, Executive Officers and Corporate Governance for information regarding our executive officers as of February 24, 2017.

20, 2019.


ITEM 1A.  RISK FACTORS

The following risks and uncertainties, together with other information set forth in this Form 10-K/A,10-K, should be carefully considered by current and future investors in our securities. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our securities.


15
Table of Contents


Risks Concerning Cimarex and its Operations

Oil, gas, and NGL prices fluctuate due to a number of uncontrollable factors beyond our control, creating a component of uncertainty in our development plans and overall operations. Declines in prices adversely affect our financial results and rate of growth in proved reserves and production.

Oil and gas markets are volatile. We cannot predict future prices. The prices we receive for our production heavily influence our revenue, profitability, access to capital, and future rate of growth. The prices we receive depend on numerous factors beyond our control. These factors include, but are not limited to, changes in domestic and global supply and demand for oil and gas, the level of domestic and global oil and gas exploration and production activity, geopolitical instability, the actions of the Organization of Petroleum Exporting Countries, weather conditions, technological advances affecting energy consumption, governmental regulations and taxes, and the price and technological advancement of alternative fuels.

Our proved oil and gas reserves and production volumes will decrease unless those reserves are replaced with new discoveries or acquisitions. Accordingly, for the foreseeable future, we expect to make substantial capital investments for the exploration and development of new oil and gas reserves. Historically, we have paid for these types of capital expenditures with cash flow provided by our production operations, our revolving credit facility, and proceeds from the sale of senior notes or equity. Low prices reduce our cash flow and the amount of oil and gas that we can economically produce and may cause us to curtail, delay, or defer certain exploration and development projects. Moreover, low prices may impact our abilities to borrow under our revolving credit facility and to raise additional debt or equity capital to fund acquisitions.

If prices decrease, we willmay be required to take write-downs of the carrying values of our oil and gas properties and/or our goodwill.


Accounting rules require that we periodically review the carrying value of our oil and gas properties and goodwill for possible impairment.

In 2016 we recognized a ceiling test impairmentsimpairment totaling $757.7 million ($481.4 million, net of tax). In 2015, we recognized ceiling test impairments in each quarter totaling $4.0 billion ($2.6 billion, net of tax).  The impairmentsimpairment resulted primarily from the impact of decreases in the 12-monthtrailing twelve-month average trailing prices for oil, natural gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. At December 31, 2016,We did not recognize any ceiling test impairments in 2017 or 2018 since 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,test. At December 31, 2018, a decline of approximately 7%24% or more in the value of the ceiling limitation would have resulted in an impairment. Because the ceiling calculation uses rolling 12-monthtrailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.


We evaluate our goodwill for impairment annually and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. We have had no goodwill impairments during the years ended December 31, 2018, 2017, and 2016.
Ineffective internal controls could impact our business and financial results.

Our internal control over financial reporting may not prevent or detect misstatements because of its inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed and we could fail to meet our financial reporting obligations. For example, in connection with the corrections made in this Form 10-K/A, management re-evaluated the effectiveness of our internal control over financial reporting as ofat December 31, 2016, andmanagement concluded that a deficiency in the design of our internal controls related to the full cost ceiling test calculation representsrepresented a material weakness in our internal control over financial reporting and, therefore, that we did not maintain effective internal control over financial reporting as of December 31, 2016. For a description of the material weakness identified by management and the remediation efforts being implemented2016, as reported in our Form 10-K/A for that material weakness, see “Part II, Item 9A — Controls and Procedures.”  If the new controls implemented to address the material weakness and to strengthen the overall internal control related to the full cost ceiling test calculation are not designed or do not operate effectively, if we are unsuccessful in implementing or following these new processes, or we are otherwise unable to remediateperiod. We have since remediated this material weakness, thishowever, there is no guarantee that we won’t experience material weaknesses in our internal control over financial reporting in the future or that we will be able to implement new controls to address such material weaknesses as necessary, which may result in untimely or inaccurate reporting of our financial statements.


16
Table of Contents


U.S. or global financial markets may impact our business and financial condition.

A credit crisis or other turmoil in the U.S. or global financial system may have a negative impact on our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. This could have an impact on our flexibility to react to changing economic and business conditions. Deteriorating economic conditions could have a negative impact on our lenders, the purchasers of our oil and gas production, and the working interest owners in properties we operate, causing them to fail to meet their obligations to us.

Failure to economically replace oil and gas reserves could negatively affect our financial results and future rate of growth.

In order to replace the reserves depleted by production and to maintain or increase our total proved reserves and overall production levels, we must either locate and develop new oil and gas reserves or acquire producing properties from others. This requires significant capital expenditures and can impose reinvestment risk for us, as we may not be able to continue to replace our reserves economically. While we occasionally may seek to acquire proved reserves, our main business strategy is to grow through exploration and drilling. Without successful exploration and development, our reserves, production, and revenues could decline rapidly, which would negatively impact the results of our operations.

Exploration and development involves numerous risks, including new governmental regulations and the risk that we will not discover any commercially productive oil or gas reservoirs. Additionally, it can be unprofitable, not only from drilling dry holes, but also from drilling productive wells that do not return a profit because of insufficient reserves or declines in commodity prices.

Our drilling operations may be curtailed, delayed, or canceled for many reasons. Factors such as unforeseen poor drilling conditions, title problems, unexpected pressure irregularities, equipment failures, accidents, adverse weather conditions, compliance with environmental and other governmental requirements, bans, moratoria, or other restrictions implemented by local governments and the cost of, or shortages or delays in the availability of, drilling and completion services could negatively impact our drilling operations.

Our proved reserve estimates may be inaccurate and future net cash flows are uncertain.

Estimates of total proved oil and gas reserves (consisting of proved developed and proved undeveloped reserves) and associated future net cash flow depend on a number of variables and assumptions. Refer to “Cautionary Information about Forward-Looking Statements”CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report. Among others, changes in any of the following factors may cause actual results to vary considerably from our estimates:

·

oil, gas, and NGL prices;
timing of development expenditures;

·

amount of required capital expenditures and associated economics;

·

recovery efficiencies, decline rates, drainage areas, and reservoir limits;

·

anticipated reservoir and production characteristics and interpretations of geologic and geophysical data;

·       ��         

production rates, reservoir pressure, unexpected water encroachment, and other subsurface conditions;

·                  oil, gas, and NGL prices;

·

governmental regulation;

·

access to assets restricted by local government action;

·

operating costs;

·

property, severance, excise, and other taxes incidental to oil and gas operations;

·


17
Table of Contents


workover and remediation costs; and

·

federal and state income taxes.

Our proved oil and gas reserve estimates are prepared by Cimarex engineers in accordance with guidelines established by the SEC. DeGolyer and MacNaughton, independent petroleum engineers, reviewedperformed an independent evaluation of our reserve estimates for properties that comprised at leastestimated net reserves representing greater than 80% of the discountedtotal future net cash flows before income taxes, using arevenue discounted at 10% discount rate,, as of December 31, 2016.

2018.


The cash flow amounts referred to in this filing should not be construed as the current market value of our proved reserves. In accordance with SEC guidelines, the estimated discounted net cash flow from proved reserves is based on the average of the previous 12twelve months’ first-day-of-the-month prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially different.

Our business depends on oil and gas pipeline and transportation facilities, some of which are owned by others.

In addition to the existence of adequate markets, our oil and natural gas production depends in large part on the proximity and capacity of pipeline systems, as well as storage, transportation, processing and fractionation facilities, most of which are owned by third parties. The inability to transport one commodity, such as gas, could also impair our ability to produce and sell other commodities, such as oil and NGLs, produced from the same wells. The lack of availability or the lack of capacity on these systems and facilities could result in the curtailment of production or the delay or discontinuance of drilling plans. This is more likely in remote areas withoutwith less established infrastructure, such as our Delaware Basin area where we and competitors have significant development activities. The lack of availability of or capacity in these facilities or the loss of these facilities due to construction delays, weather, fire, or other reasons, for an extended period of time could negatively affect our revenues.

A limited number of companies purchase a majority of our oil, NGLsgas, and natural gas.NGLs. The loss of a significant purchaser could have a material adverse effect on our ability to sell production.

Federal and state regulation of oil and natural gas, local government activity, adverse court rulings, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could adversely affect our ability to produce and market oil and natural gas.

Hedging

Commodity price derivative transactions may limit our potential gains and involve other risks.

To limit our exposure to price risk, we enter into hedgingderivative agreements from time to time, and use commodity derivatives.  Hedgestime. Commodity price derivatives limit volatility and increase the predictability of a portion of our cash flow. These transactions also limit our potential gains when oil and gas prices exceed the prices established by the hedges.

derivatives.

In certain circumstances, hedgingderivative transactions may expose us to the risk of financial loss, including instances in which:

·

the counterparties to our hedgingderivative agreements fail to perform;

·

there is a sudden unexpected event that materially increases oil and natural gas prices; or

·

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement.

derivative agreement. 

Because we account for derivative contracts under mark-to-market accounting, during periods we have hedgingderivative transactions in place we expect continued volatility in derivative gains orand losses on our income statement of operations as changes occur in the relevant price indexes.

The adoption of derivatives legislation could have an adverse effect on our ability to use derivative instruments as hedges against fluctuating commodity prices.

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC

18
Table of Contents


and the Commodities Futures Trading Commission (CFTC)(“CFTC”), to establish regulations for implementation of many of its provisions. The Dodd-Frank Act contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that cash collateral (margin) be posted for such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, such as Cimarex, and it includes a number of defined terms used in determining how this exemption applies to particular derivative transactions and the parties to those transactions.

We have satisfied the requirements for the commercial end-user exception to the clearing requirement and intend to continue to engage in derivative transactions. In December 2015, the CFTC approved final rules on margin requirements that will have an impact on our hedgingderivative counterparties and an interim final rule exemption from the margin requirements for certain uncleared swaps with commercial end-users. The final rules did not impose additional requirements on commercial end-users. The ultimate effect of these new rules and any additional regulations is currently uncertain. New rules and regulations in this area may result in significant increased costs and disclosure obligations as well as decreased liquidity as entities that previously served as hedgederivative counterparties exit the market.

We have been an early entrant into new or emerging resource plays. As a result, our drilling results in these areas are uncertain. The value of our undeveloped acreage may decline and we may incur impairment charges if drilling results are unsuccessful.

New or emerging oil and gas resource plays have limited or no production history. Consequently, in those areas it is difficult to predict our future drilling costs and results. Therefore, our cost of drilling, completing, and operating wells in these areas may be higher than initially expected. Similarly, our production may be lower than initially expected, and the value of our undeveloped acreage may decline if our results are unsuccessful. As a result, we may be required to impair the carrying value of our undeveloped acreage in new or emerging plays.

Furthermore, unless production is established during the primary term of certain of our undeveloped oil and gas leases, the leases will expire, and we will lose our right to develop those properties.

Competition in our industry is intense and many of our competitors have greater financial and technological resources.

We operate in the competitive area of oil and gas exploration and production. Many of our competitors are large, well-established companies that have larger operating staffs and greater capital resources. These competitors may be willing to pay more for exploratory prospects and productive oil and gas properties. They may also be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.

Because our activity is also concentrated in areas of heavy industry competition, there is heightened demand for personnel, equipment, power, services, facilities, and resources, resulting in higher costs than in other areas. Such intense competition also could result in delays in securing, or the inability to secure, the personnel, equipment, power, services, resources, or facilities necessary for our development activities, which could negatively impact our production volumes. We also face higher costs in remote areas where vendors can charge higher rates due to that remoteness along withand the inability to attract employees to those areas, andas well as the vendors’ ability to deploy their resources in easier to accesseasier-to-access areas.

We are subject to complex laws and regulations that can adversely affect the cost, manner, and feasibility of doing business.

Exploration, production, and the sale of oil and gas are subject to extensive laws and regulations, including those implemented to protect the environment, human health and safety, and wildlife. Federal, state, and local regulatory agencies frequently require permitting and impose conditions on our activities. During the permitting process, these regulatory agencies often exercise considerable discretion in both the timing and scope of the permits, and the public, including special interest groups, often has an opportunity to influence the timing and outcome of the process. The requirements or conditions imposed by these agencies can be costly and can delay the commencement of our operations. In addition, a number of initiatives had beenwere put forth by the Obama administration in the form of Presidential or Secretarial Memoranda, which are still in effect, and have the potential to impact the cost of doing business or could result in substantial delays in permitting, drilling, and other oil and gas activities.  One example is the Presidential Memorandum on “no net loss” which will take the form

19
Table of agency action by the Department of Interior, EPA and other agencies to ensure that harmful effects to lands are avoided, minimized and those which remain mitigated up to and including prohibiting actions which may have been previously allowed or requiring compensation.

Contents



Failing to comply with any of the applicable laws and regulations, or Presidential initiatives, could result in the suspension or termination of our operations and subject us to administrative, civil, and criminal liabilities and penalties. Such costs could have a material adverse effect on both our financial condition and operations.  In addition, it is uncertain what impact the 2016 U.S. presidential and congressional elections will have on the energy industry.

Environmental matters and costs can be significant.

As an owner, lessee, or operator of oil and gas properties, we are subject to various complex, stringent, and constantly evolving environmental laws and regulations. Our operations inherently create the risk of environmental liability to the government and private parties stemming from our use, generation, handling, and disposal of water and

waste materials, as well as the release of hydrocarbons or other substances into the air, soil, or water. The environmental laws and regulations to which we are subject impose numerous obligations applicable to our operations, including: the acquisition of permits before conducting regulated activities associated with drilling for and producing oil and gas; the restriction of types, quantities, and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, waters of the United States, and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Liabilities under certain environmental laws can be joint and several and may in some cases be imposed regardless of fault on our part such as where we own a working interest in a property operated by another party. We also could be held liable for damages or remediating lands or facilities previously owned or operated by others regardless of whether such contamination resulted from our own actions and regardless if we were in compliance with all applicable law at the time. Further, claims for damages to persons or property, including natural resources, may result from the environmental, health, and safety impacts of our operations. SinceBecause these environmental risks generally are not fully insurable and can result in substantial costs, such liabilities could have a material adverse effect on both our financial condition and operations.

Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, pollutants, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, discharge, transportation, and disposal of pollutants and solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The most significant of these environmental laws are as follows:

·

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as CERCLA or the Superfund law, and comparable state laws, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

·

The Oil Pollution Act of 1990 (OPA)(“OPA”), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States;

·

The Resource Conservation and Recovery Act (RCRA)(“RCRA”), as amended, and comparable state statutes, which governs the treatment, storage, and disposal of solid waste;

·

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act (CWA)(“CWA”), which governs the discharge of pollutants, including natural gas wastes, into federal and state waters;

·


20
Table of Contents


The Safe Drinking Water Act (SDWA)(“SDWA”), which governs the disposal of wastewater in underground injection wells; and

·

The Clean Air Act (CAA)(“CAA”) which governs the emission of pollutants into the air.

We believe we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, OPA, CWA, SDWA, CAA and related state and local laws and regulations. We also believe we hold all necessary and up-to-date permits, registrations, and other authorizations required under such laws and regulations. Although the current costs of managing our wastes as they presently are classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes and have a material adverse effect on our financial condition and operations.

Federal regulatory initiatives relating to the protection of threatened or endangered species could result in increased costs and additional operating restrictions or delays.

The Federal Endangered Species Act (ESA)(“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service (FWS)(“FWS”) may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and natural gas leases in areas where certain species are currently listed as threatened or endangered, or could be listed as such, under the ESA. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, and Oklahoma, where we conduct operations, as a threatened species under the ESA. Listing of the lesser prairie chicken as a threatened species imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm, or otherwise result in a “taking” of this species. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (WAFWA)(“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We entered into a voluntary Candidate Conservation Agreement (CCA)(“CCA”) with the WAFWA, whereby we agreed to take certain actions and limit certain activities, such as limiting drilling on certain portions of our acreage during nesting seasons, in an effort to protect the lesser prairie chicken. SuchOn February 9, 2018, the FWS announced the listing of the Texas Hornshell, a fresh water mussel species in areas including New Mexico and Texas where we operate in the Permian Basin, as an endangered species. We also intend to enter into a CCA concerning voluntary conservation actions with respect to the Texas Hornshell. Participating in CCAs could result in increased costs to us from species protection measures, time delays or limitations on drilling activities, which costs, delays or limitations may be significant. While a federal judge in Texas vacated the listing of the lesser prairie chicken in 2015, listing petitions continue to be filed with the FWS which could impact our operations. Many non-governmental organizations (NGOs)(“NGOs”) work closely with the FWS regarding the listing of many species, including species with broad and even nationwide ranges. The recent listing of the Mexican Long Nosed bat, whose habitat includes the Permian Basin where we operate, is an example of the NGOs’ influence on ESA listing decisions. The increase in endangered species listings may impact our ability to explore for or produce oil and gas in certain areas and increase our costs.

Our hydraulic fracturing activities are subject to risks that could negatively impact our operations and profitability.


We use hydraulic fracturing for the completion of almost all of our wells. Hydraulic fracturing is a process that involves pumping fluid and proppant at high pressure into a hydrocarbon bearing formation to create and hold open fractures. Those fractures enable gas or oil to move through the formation’s pores to the well bore. Typically, the fluid used in this process is primarily water. In plays where hydraulic fracturing is necessary for successful development, the demand for water may exceed the supply. A lack of readily available water or a significant increase in the cost of water could cause delays or increased completion costs.


21
Table of Contents


While hydraulic fracturing historically has been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation from federal agencies. For example, the EPA has asserted federal regulatory authority over certain hydraulic-fracturinghydraulic fracturing activities under the SDWA involving the use of diesel fuels and published permitting guidance in February 2014 addressing the use of diesel in fracturing operations. Although the EPA has delegated the permitting authority for the

SDWA’s Underground Injection Control Class II programs in Oklahoma, Texas, and New Mexico where we maintain operational acreage, the EPA is encouraging state programs to review and consider the use of such draft guidance.

In addition, on March 26, 2015, the federal BLM published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, development of appropriate plans for managing flowback water that returns to the surface, increased standards for interim storage of recovered waste fluids, and submission to the BLM of detailed information on the geology, depth, and location of preexisting wells. This rule originally was scheduled to take effect on June 24, 2015. However, the rule is the subject of several pending lawsuits filed by industry groups, two Indian tribes, and at least four states, alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. The federal judge has enjoined the rule while the case is pending. The district court held that BLM did not have jurisdiction to promulgate the rule. The Obama Justice Department appealed and that appeal is pending.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has concludedprepared a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA’s draft report was released on June 4, 2015. The findings of the report suggest that hydraulic fracturing does not pose a systemic risk to groundwater although there are risks to both groundwater and soils posed by inadequate water handling practices in certain situations. A public comment period on the report was open until August 28, 2015, and a series of public hearings were conducted by the EPA’s Scientific Advisory Board (SAB)(“SAB”) throughout the fall of 2015. The EPA issued its final report and has reached two different topline conclusions, although the content of the study itself remains unchanged. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing.

Additionally, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Most producing states, including Texas and Colorado, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturinghydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.

Any of the above factors could have a material adverse effect on our financial position, results of operations, or cash flows and could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, our fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

The adoption of climate change legislation or regulations restricting emission of greenhouse gases, investor pressure concerning climate-related disclosures, and lawsuits could result in increased operating costs and reduced demand for the oil and natural gas we produce.

produce as well as reductions in the availability of capital.

Studies have suggested that emission of certain gases, commonly referred to as greenhouse gases (GHGs)(“GHGs”), may be impacting the earth’s climate. Methane, a primary component of natural gas, and carbon dioxide, also present in natural gas as a secondary product, sometimes considered an impurity or a by-product of the burning of oil and natural gas, are examples of GHGs. The U.S. Congress and various states have been evaluating, and in some cases implementing, climate-related legislation and other regulatory initiatives that restrict emissions of GHGs. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under existing provisions of the Federal Clean Air Act that establish Prevention of Significant Deterioration (PSD)(“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD and/or Title V permits under EPA’s GHG

22
Table of Contents


Tailoring Rule for their GHG emissions also may be required to meet “Best Available Control Technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. In recent proposed rulemaking, EPA is widening the scope of annual GHG reporting to include not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and natural gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In January 2015, President Obama announced a series of administration actions to reduce methane emissions, including rulemaking by the EPA and the BLM as well as updating of standards by the Department of Transportation’s Pipeline and Hazardous Materials Administration. The previous administration intended to promulgate proposed climate change rulemaking aimed at reducing GHG emissions by 45% by 2025 compared to 2012 levels. These proposals target both new and existing sources. On January 22, 2016, the Department of the Interior announced its proposed emissions mandate on oil and natural gas producers who operate on federal and Indian lands. While this rule was finalized in November of 2016, it is currently being challenged by several states and industry. While we expect new legislation and regulations to increase the cost of business, at this time it is not possible to quantify the impact on our business. Any such future laws and final regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to develop and implement best management practices aimed at reducing GHG emissions, install and maintain emissions control technologies, as well as monitor and report on GHG emissions associated with our operations, which would increase our operating costs, and such requirements also could adversely affect demand for the oil and natural gas that we produce.

The following is a summary of potential climate-related risks that could adversely affect Cimarex:
Transition Risks. Transition risks are risks related to the transition to a lower-carbon economy and include policy, legal, technology, and market risks.
Policy and Legal Risks. Policy risks include policy actions that attempt to contract actions that contribute to adverse effects of climate change or policy actions that seek to promote adaptation to climate change. Examples include implementing carbon-pricing mechanisms to reduce GHG emissions (which would increase the costs of our doing business), shifting energy use toward lower emission sources (which could lower demand for our oil and gas production, resulting in lower prices and lower revenues), adopting energy-efficiency solutions (which also could lower demand for our oil and gas production, resulting in lower prices and lower revenues), encouraging greater water efficiency measures (which would increase our costs of production), and promoting more sustainable land-use practices (which also would increase our costs of production and could impact our ability to operate in certain areas). Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets. Legal and litigation risks include potential lawsuits claiming failure to mitigate impacts of climate change, failure to adapt to climate change, and the insufficiency of disclosure around material financial risks.
Technology Risk. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on Cimarex. The development and use of emerging technologies such as renewable energy, battery storage, and energy efficiency may lower demand for oil and gas, resulting in lower prices and revenues, and increase our costs.
Market Risk. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas, as climate-related risks and opportunities are increasingly taken into account. This could lower demand for our oil and gas production, resulting in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In addition, there have also been efforts in recent years to influence the investment community, including investment advisers and certain sovereign wealth, pension, and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental

23
Table of Contents


activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations, and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil, NGL, and gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While we are currently not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Reputation Risk. Climate change has been identified as a potential source of reputational risk tied to changing customer or community perceptions of an organization’s contribution to or detraction from the transition to a lower-carbon economy. This could lower demand for our oil and gas production, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries. This may also put pressure on investment managers to shift investments to less carbon-intensive industries and alternative energy industries, limiting our access to capital.
Physical Risks. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes or floods) or longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts such as supply chain disruption. Potential physical risks also include changes in water availability, sourcing, and quality, which could impact drilling and completions operations. These physical risks could cause increased costs, production disruptions, and lower revenues.
Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to engage in hydraulic fracturing during completion operations and to dispose of saltwater produced in connection with our oil and gas production, which could limit our ability to produce oil and gas economically and have a material adverse effect on our business.

We dispose of large volumes of saltwater produced in connection with our drilling and production operations pursuant to permits issued to us or third partythird-party operators of disposal wells by governmental authorities overseeing produced water disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

There exists a growing concern that hydraulic fracturing during well completion operations and the injection of

produced water into belowgroundunderground disposal wells triggers seismic activity in certain areas, including Oklahoma and Texas, where we operate. In response to these concerns, regulators in some states are pursuing initiatives designed to impose additional requirements in connection with hydraulic fracturing and in the permitting of saltwater disposal wells or otherwise to assess any relationship between seismicity and these oil and gas operations. For example, in 2014, the Oklahoma Corporation Commission began adopting rules for operators of saltwater disposal wells in certain seismically-active areas, or Areas of Interest, in the Arbuckle formation, requiring operators to monitor and record well pressure and discharge volume on a daily basis and further requiring operators of wells permitted for disposal of 20,000 barrels per day or more of saltwater to conduct mechanical integrity testing. Throughout 2015 and 2016, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division, or OGCD, issued a series of directives, expanding the areas of interest for induced seismicity and enhanced disposal restrictions and limiting the depths at which produced water could be injected or, in the alternative, reducing disposal volumes. Additional regulations and restrictions are possible as more is understood about this issue. In addition to and separate from induced seismicity associated with injection, the OGCD has issued guidelines to operators to follow when engaged in well stimulation activities, which some studies now seem to correlate with a small number of low intensity seismic events.

In addition, in 2014 the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells in Texas that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. If a permittee or a prospective permittee fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well.


24
Table of Contents


The adoption and implementation of any new laws, regulations, or directives that restrict our ability to stimulate wells or to dispose of produced water, by changing the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in such wells, restricting disposal well locations or otherwise, or by requiring us or third parties who dispose of our saltwater to shut down disposal wells, could increase disposal costs or require us to shut in a substantial number of our oil and natural gas wells or otherwise have a material adverse effect on our ability to produce oil and gas economically and, accordingly, could materially and adversely affect our business, financial condition, and results of operations.

We could also face lawsuits alleging that seismic activity occurred as a result of completions or water disposal activities, resulting in damage to persons and property.

A substantial portion of our producing properties are located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.

A substantial portion of our producing properties are geographically concentrated in the Permian Basin in Texas and New Mexico and our Cana area in the Mid-Continent region in Oklahoma, with these two areas comprising approximately 52%57% and 47%43%, respectively, of our oil, gas, and NGL production and approximately 61%64% and 39%36%, respectively, of our oil, gas, and NGL revenues for the year ended December 31, 2016.2018. Approximately 37%57% of our estimated proved reserves were located in the Permian Basin and approximately 63%43% of our estimated proved reserves were located in the Mid-Continent region as of December 31, 2016.

2018.

Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors relative to our competitors that have more geographically dispersed operations. These factors include, among others: (i) the prices of crude oil and natural gas produced from wells in the regions and other regional supply and demand factors, including gathering, pipeline, and rail transportation capacity constraints; (ii) the availability of rigs, equipment, oil field services, supplies, and labor; (iii) the availability of processing and refining facilities; and (iv) infrastructure capacity. In addition, our operations in the Permian Basin and Mid-Continent region, as well as other areas, may be adversely affected by severe weather events such as floods, lightning, ice and other storms, and tornadoes, which can intensify competition for the items described above during months when drilling is possible and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations including concerning hydraulic fracturing and waste waterwastewater disposal as discussed above in “Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to engage in hydraulic fracturing during completion operations and to dispose of saltwater produced in connection with our oil and gas production, which could limit our ability to produce oil and gas

economically and have a material adverse effect on our business”, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents, or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations, and cash flows.

We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.

Our horizontal drilling operations utilize some of the latest drilling and completion techniques. The risks orof such techniques include, but are not limited to, the following:

·

landing the wellbore in the desired drilling zone;

·

staying in the desired drilling zone while drilling horizontally through the formation;

·

running casing the entire length of the wellbore;

·

being able to run tools and other equipment consistently through the horizontal wellbore;

·

the ability to fracture stimulate the planned number of stages;

·

the ability to run tools the entire length of the wellbore during completion operations; and

·

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.


25
Table of Contents


Any of the above factors could have a material adverse effect on our financial position, results of operations, or cash flows.

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

We may be subject to information technology system failures, network disruptions, and breaches in data securityand our business, financial position, results of operations, and cash flows could be negatively affected by such security threats and disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats such as attempts to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing facilities, pipelines and refineries; and threats from terrorist acts. Cybersecurity attacks are becoming more sophisticated and

include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data, and “ransomware” attacks where data is locked unless a payment is made, any of which could have an adverse effect on our reputation, business, financial condition, results of operations, or cash flows. While we have not suffered any material losses relating to such attacks, there can be no assurance that we will not suffer such losses in the future.

We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. In addition to cybersecurity and data security threats, other information system failures and network disruptions could have a material adverse effect on our ability to conduct our business. We could experience system failures due to power or telecommunications failures, human error, natural disasters, fire, sabotage, hardware or software malfunction or defects, computer viruses, intentional acts of vandalism or terrorism and similar acts or occurrences. Such system failures could result in the unanticipated disruption of our operations, communications, or processing of transactions, as well as loss of, or damage to, sensitive information, facilities, infrastructure and systems essential to our business and operations, the failure to meet regulatory standards and the reporting of our financial results, and other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations, and cash flows.

A cyber attack involving our information systems and related infrastructure, or those of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to:

·

unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

·

data corruption or operational disruption of production-related infrastructure could result in a loss of production, or accidental discharge;

·

a cyber attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our major development projects;

·

a cyber attack on third partythird-party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues; and

·


26
Table of Contents


a cyber attack on our accounting or accounts payable systems could expose us to liability to employees and third parties if their personal identifying information is obtained.

These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability, which could have a material adverse effect on our financial condition, results of operations, or cash flows.


While management has taken steps to address these concerns by implementing network security and internal control measures to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure, our implementation of such procedures and controls may result in increased costs, and there can be no assurance that a system failure or data security breach will not occur and have a material adverse effect on our business, financial condition, and results of operations. In addition, as cybersecurity threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cybersecurity or information technology infrastructure vulnerabilities.

Our limited ability to influence operations and associated costs on non-operated properties could result in economic losses that are partially beyond our control.


For the year ended December 31, 2016,2018, other companies operated approximately 22%19% of our net production. Our success in properties operated by others depends upon a number of factors outside of our control. These factors include timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other

participants in drilling wells, selection of technology, and maintenance of safety and environmental standards. Our dependence on the operator and other working interest owners for these projects could prevent the realization of our targeted returns on capital in drilling or acquisition activities.

Our business involves many operating risks that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to hazards and risks inherent in drilling for oil and gas, such as fires, natural disasters, explosions, formations with abnormal pressures, casing collapses, uncontrollable flows of underground gas, blowouts, surface cratering, pipeline ruptures, or cement failures. Other such risks include theft, vandalism, and environmental hazards such as natural gas leaks, oil spills, and discharges of toxic gases. Any of these risks can cause substantial losses resulting from:

·

injury or loss of life;

·

damage to, loss of or destruction of, property, natural resources and equipment;

·

pollution and other environmental damages;

·

regulatory investigations, civil litigation, and penalties;

·

damage to our reputation;

·

suspension of our operations; and

·

costs related to repair and remediation.

In addition, our liability for environmental hazards may include conditions created by the previous owners of properties that we purchase or lease.

We maintain insurance coverage against some, but not all, potential losses. We do not believe that insurance coverage for all environmental damages that could occur is available at a reasonable cost. Losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operation.


27
Table of Contents


We may not be able to generate enough cash flow to meet our debt obligations.

At December 31, 2016,2018, our long-term debt consisted of $750 million of 4.375% senior notes due in 2024 and $750 million of 5.875%3.90% senior notes due in 2022.2027. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, contractual commitments,capital expenditures, operating expenses, and capital expenditures.

contractual commitments, as well as the pending anticipated closing of the acquisition of Resolute in the first quarter of 2019.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations, and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under our existing revolving credit facility bears interest at floating rates.

We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:

·

reducing or delaying capital expenditures;

·

seeking additional debt financing or equity capital;

·

selling assets; or

·

restructuring or refinancing debt.

We may be unable to complete any such strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

The instruments governing our indebtedness contain various covenants limiting the discretion of our management in operating our business.

The indenture governing our senior notes and our credit agreement contain various restrictive covenants that may limit management’s discretion in certain respects. In particular, these agreements limit Cimarex’s and its subsidiaries’ ability to, among other things:

·

create certain liens;

·

consolidate, merge, or transfer all, or substantially all, of our assets and our restricted subsidiaries;

· or

enter into sale and leaseback transactions.

In addition, our revolving credit agreement requires us to maintain a total debt to capitalization ratio (as defined in the credit agreement) of not more than 65%. See Note 3 to the Consolidated Financial Statements for further information.

If we fail to comply with the restrictions in the indenture governing our senior notes or the agreement governing our credit facility or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, lenders may be able to terminate any commitments they had made to make available further funds.


28
Table of Contents


Our acquisition activities may not be successful, which may hinder our replacement of reserves and adversely affect our results of operations.

The successful acquisition of properties requires an assessment of several factors, including:

·

geological risks and recoverable reserves;

·

future oil and gas prices and their appropriate market differentials;

·

operating costs; and

·

potential environmental risks and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Furthermore, the seller may be unwilling or unable, such as in a corporate acquisition such as our acquisition of Resolute, to provide effective contractual protection against all or part of the identified problems.

For additional risks related to our pending acquisition of Resolute, see below “Risks Concerning Cimarex’s Pending Merger with Resolute Energy Corporation.”

We may lose leases if production is not established within the time periods specified in the leases.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire any proved undeveloped reserves associated with suchand the amounts spent for those leases will be removed from our proved reserves.lost. The combined net acreage expiring in the next three years represents 3.5%approximately 4.7% of our total net undeveloped acreage at December 31, 2016.2018. At that date, we had leases representing 85,669193,180 net acres expiring in 2017, 41,9812019, 55,978 net acres expiring in 2018,2020, and 68,81521,598 net acres expiring in 2019.2021. Our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We regularly sell non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development of and increasing efficiencies in such core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, and the availability of purchasers willing to acquire the assets with terms we deem acceptable.

Sellers oftenat times retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

In addition, with respect to offshore assets, if purchasers declare bankruptcy, the United States Department of Interior may pursue former owners for decommissioning expenses, which can be substantial. See Note 8 to the Consolidated Financial Statements for further discussion regarding our asset retirement obligations.

Competition for experienced technical personnel may negatively impact our operations.

Our exploratory and development drilling success depends, in part, on our ability to attract and retain experienced professional personnel. The loss of any key executives or other key personnel could have a material adverse effect on our operations. As we continue to develop our asset base and the scope of our operations, our future profitability will depend on our ability to attract and retain qualified personnel, particularly individuals with a strong background in geology, geophysics, engineering, and operations.


29
Table of Contents


We are involved in various legal proceedings, the outcome of which could have an adverse effect on our liquidity.

In the normal course of business, we haveare involved with various lawsuits and related disputed claims, including but not limited to claims concerning title, royalty payments, environmental issues, personal injuries, and contractual issues. Although we currently believe the resolution of these lawsuits and claims, individually or in the aggregate, would not have a material adverse effect on our financial condition or results of operations, our assessment of our current litigation and other legal proceedings could change in light of the discovery of facts with respect to legal actions or other proceedings pending against us not presently known to us or determinations by judges, juries, or other finders of fact that are not in accord with our evaluation of the possible liability or outcome of such proceedings. Therefore, there can be no assurance that outcomes of future legal proceedings would not have an adverse effect on our liquidity and capital resources.

For litigation risks related to our pending acquisition of Resolute, see below “Risks Concerning Cimarex’s Pending Merger with Resolute Energy Corporation.”

Certain federal income tax deductions currently available with respect to naturaloil and gas and oil exploration and development may be limited or eliminated as a result of recently enacted or future legislation.


On December 22, 2017, the United States enacted H.R.1, commonly referred to as the Tax Cuts and Jobs Act or U.S. Tax Reform. H.R.1, among other things, includes changes to U.S. federal tax rates, imposes new limitations on the utilization of net operating losses and the deductibility of interest and executive compensation, temporarily allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. Various proposed regulations have been issued regarding H.R.1. Until final regulations are issued the full impact of changes to the company is not known at this time. In addition, various proposals have been made recommending the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Legislation is oftenFuture legislation may be introduced in Congress which would implement many of these proposals. These changes include, but are not limited to,to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could have an adverse effect on our financial position.

position, results of operations, and cash flows, including the payment of cash taxes earlier than expected.

Risks Concerning Cimarex’s Pending Merger with Resolute Energy Corporation

The merger is subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all.

The merger is subject to a number of other conditions beyond Cimarex’s and Resolute’s control that may prevent, delay, or otherwise materially adversely affect its completion, including the approval of the merger proposal by Resolute’s stockholders at its meeting currently scheduled for February 22, 2019. Neither Cimarex nor Resolute can predict whether and when these other conditions will be satisfied. Any delay in completing the merger could cause the combined company not to realize some or all of the synergies expected to be achieved if the merger is successfully completed within its expected time frame.

Cimarex and Resolute will incur substantial transaction fees and merger-related costs in connection with the merger.

Cimarex and Resolute have incurred and expect to continue to incur non-recurring transaction fees, which include legal and advisory fees and substantial merger-related costs associated with completing the merger, combining the operations of the two companies, and achieving desired synergies. Additional unanticipated costs may be incurred in the course of the integration of the businesses of Cimarex and Resolute. The companies cannot be certain that the realization of other benefits related to the integration of the two businesses will offset the transaction and merger-related costs in the near term, or at all.


30
Table of Contents


Completion of the merger may trigger change in control or other provisions in certain agreements to which Resolute is a party.

The completion of the merger may trigger change in control or other provisions in certain agreements to which Resolute is a party. If Cimarex and Resolute are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if Cimarex and Resolute are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to Resolute or the combined company.

Lawsuits have been filed against Resolute, the directors of Resolute, Cimarex, and the subsidiaries of Cimarex created to effect the acquisition of Resolute challenging the adequacy of the disclosures made in the proxy statement/prospectus concerning the merger and an adverse ruling in one or more of these lawsuits may prevent the merger from being completed.

As of January 25, 2019, Resolute, the directors of Resolute, and in two of the cases, Cimarex, Merger Sub 1, and Merger Sub 2, have been named as defendants in five purported stockholder class actions challenging the adequacy of the disclosures to Resolute stockholders made in the proxy statement/prospectus concerning the merger. Three complaints were filed in the U.S. District Court for the District of Delaware, one complaint was filed in the U.S. District Court for the Southern District of New York, and one complaint was filed in U.S. District Court for the District of Colorado. Additional lawsuits arising out of the merger may be filed in the future. There can be no assurance that defendants will be successful in the outcome of the pending or any potential future lawsuits. A preliminary injunction could delay or jeopardize the completion of the merger.

Risks Relating to the Combined Company Following the Merger

If completed, the merger may not achieve its intended results, and Cimarex and Resolute may be unable to successfully integrate their operations.

Cimarex and Resolute entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, expanding Cimarex’s asset base and creating synergies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Cimarex and Resolute can be integrated in an efficient and effective manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company’s ongoing businesses, processes, and systems or inconsistencies in standards, controls, procedures, practices, policies, and compensation arrangements, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger. The combined company’s results of operations could also be adversely affected by any issues attributable to either company’s operations that arise from or are based on events or actions that occur prior to the closing of the merger. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. The integration process is subject to a number of uncertainties, and no assurance can be given whether anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company’s future business, financial condition, operating results, and prospects.

The combined company is expected to incur expenses related to the integration of Cimarex and Resolute.

The combined company is expected to incur expenses in connection with the integration of Cimarex and Resolute. There are a large number of processes, policies, procedures, operations, technologies, and systems that must be integrated, including purchasing, accounting and finance, sales, billing, payroll, pricing, revenue management, maintenance, marketing, and benefits. While Cimarex and Resolute have assumed that a certain level of expenses will be incurred, there are many factors beyond their control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These integration expenses likely will result in the combined company taking charges against earnings following the completion of the merger, and the amount and timing of such charges are uncertain at present.


31
Table of Contents


Uncertainties associated with the merger may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.

Cimarex and Resolute are dependent on the experience and industry knowledge of their officers and other key employees to execute their business plans. Each company’s success until the merger and the combined company’s success after the merger will depend in part upon the ability of Cimarex and Resolute to retain key management personnel and other key employees. Current and prospective employees of Cimarex and Resolute may experience uncertainty about their roles within the combined company following the merger, which may have an adverse effect on the ability of Cimarex and Resolute to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of Cimarex and Resolute to the same extent that Cimarex and Resolute have previously been able to attract or retain their own employees.



32

Table of Contents


ITEM 1B.  UNRESOLVED STAFF COMMENTS
None.

None.

ITEM 3.  LEGAL PROCEEDINGS

The information set forth under the heading “Litigation” in Note 10 of the Notes to the Consolidated Financial Statements included in Part II, Item 8 of this Annual Report on Form 10-K/A10-K, is incorporated by reference in response to this item.

For information regarding litigation related to the pending acquisition of Resolute, which Cimarex believes is without merit and intends to defend vigorously, see “Risk Factors—Risks Concerning Cimarex’s Pending Merger with Resolute Energy Corporation.” Cimarex does not believe the ultimate resolution of the pending acquisition litigation will have a material adverse effect on our financial condition or results of operations.


ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.



33

Table of Contents


PART II

ITEM 5.  MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our $0.01 par value common stock trades on the New York Stock Exchange (NYSE)(“NYSE”) under the symbol XEC. A cash dividend was paid to stockholders in each quarter of 2016.2018. Future dividend payments will depend on the company’s level of earnings, financial requirements, and other factors considered relevant by the Board of Directors.

Stock Prices and Dividends by Quarter.  The following table sets forth, for the periods indicated, the high and low sales price per share of our common stock on the NYSE and the per share dividends declared during the period.

 

 

 

 

 

 

Dividends

 

 

 

 

 

 

 

Declared Per

 

2016

 

High

 

Low

 

Share

 

First Quarter

 

$

100.07

 

$

72.77

 

$

0.08

 

Second Quarter

 

$

123.48

 

$

93.21

 

$

0.08

 

Third Quarter

 

$

136.95

 

$

112.19

 

$

0.08

 

Fourth Quarter

 

$

146.96

 

$

118.59

 

$

0.08

 

 

 

 

 

 

 

Dividends

 

 

 

 

 

 

 

Declared Per

 

2015

 

High

 

Low

 

Share

 

First Quarter

 

$

118.87

 

$

91.74

 

$

0.16

 

Second Quarter

 

$

132.18

 

$

108.59

 

$

0.16

 

Third Quarter

 

$

118.87

 

$

97.23

 

$

0.16

 

Fourth Quarter

 

$

124.91

 

$

85.00

 

$

0.16

 


The closing price of Cimarex stock as reported on the NYSE on January 31, 2017,2019, was $135.21.$75.34. At January 31, 2017,2019, Cimarex’s 95,121,49295,755,298 shares of outstanding common stock were held by approximately 1,3931,618 stockholders of record.

Issuer Purchases of Equity Securities
The following table sets forth information with respect toregarding repurchases of our common stock during the equity compensation plans available to directors, officers, and employees of the company atyear ended December 31, 2016:

 

 

 

 

 

 

(c)

 

 

 

 

 

 

 

Number of securities

 

 

 

(a)

 

 

 

remaining available

 

 

 

Number of securities

 

(b)

 

for future issuance

 

 

 

to be issued upon

 

Weighted-average

 

under equity

 

 

 

exercise of

 

exercise price of

 

compensation plans

 

 

 

outstanding options,

 

outstanding options,

 

(excluding securities

 

Plan Category

 

warrants, and rights

 

warrants, and rights

 

reflected in column (a))

 

Equity compensation plans approved by security holders

 

307,810

 

$

101.72

 

3,287,830

 

Equity compensation plans not approved by security holders

 

—

 

—

 

—

 

Total

 

307,810

 

$

101.72

 

3,287,830

 

36

2018. The shares repurchased represent shares of our common stock that employees elected to surrender to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Cimarex does not consider this a share buyback program.
Period Total number of shares purchased Average price paid per share Total number of shares purchased as part of publicly announced plans or programs Maximum number of shares that may yet be purchased under the plans or programs
January 1-31, 2018 2,421
 $126.16
 —
 —
April 1-30, 2018 3,527
 98.86
 —
 —
May 1-31, 2018 2,970
 98.37
 —
 —
July 1-31, 2018 49,241
 99.80
 —
 —
September 1-30, 2018 6,123
 89.73
 —
 —
November 1-30, 2018 1,174
 91.37
 —
 —
December 1-31, 2018 74,790
 75.22
 —
 —
Total 140,246
 $86.58
 —
 —

34
Table of Contents



Stock Performance Graph

The following graph comparesshows the cumulative 5-yearfive-year total return attained by stockholders on Cimarex Energy Co.’s common stock relative to the cumulative total returns of the S&P 500 index, the Dow Jones US Exploration & Production index, and the S&P Oil & Gas Exploration & Production index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from December 31, 20112013 to December 31, 2016.2018. The stock price performance included in this graph is not necessarily indicative of future stock price performance.

 

 

12/2011

 

12/2012

 

12/2013

 

12/2014

 

12/2015

 

12/2016

 

Cimarex Energy Co.

 

$

100.00

 

$

93.95

 

$

171.90

 

$

174.58

 

$

148.03

 

$

225.95

 

S&P 500

 

$

100.00

 

$

116.00

 

$

153.58

 

$

174.60

 

$

177.01

 

$

198.18

 

Dow Jones US Exploration & Production

 

$

100.00

 

$

105.82

 

$

139.52

 

$

124.48

 

$

94.94

 

$

118.19

 

S&P Oil & Gas Exploration & Production

 

$

100.00

 

$

103.65

 

$

132.14

 

$

118.15

 

$

77.80

 

$

103.36

 


COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN*
Among Cimarex Energy Co., the S&P 500 Index,
the Dow Jones US Exploration & Production Index, and the S&P Oil & Gas Exploration & Production Index
chart-298b7327eb0e5f8c9d3.jpg
* $100 invested in 12/31/13 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.

A tabular presentation of the data in the above graph is provided below.
 2013 2014 2015 2016 2017 2018
Cimarex Energy Co.$100.00
 $101.56
 $86.11
 $131.44
 $118.33
 $60.17
S&P 500$100.00
 $113.69
 $115.26
 $129.05
 $157.22
 $150.33
Dow Jones US Exploration & Production$100.00
 $89.23
 $68.05
 $84.71
 $85.81
 $70.57
S&P Oil & Gas Exploration & Production$100.00
 $89.41
 $58.87
 $78.22
 $73.29
 $58.99


35

Table of Contents


ITEM 6.  SELECTED FINANCIAL DATA


The selected financial data set forth below should be read in conjunction with the Consolidated Financial Statements and accompanying notes thereto provided in Item 8 of this report.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

2013

 

2012

 

 

 

(in millions, except per share amounts)

 

Operating Results:

 

 

 

 

 

 

 

 

 

 

 

Oil, gas and NGL sales

 

$

1,221

 

$

1,418

 

$

2,373

 

$

1,953

 

$

1,582

 

Total Revenues (1)

 

$

1,257

 

$

1,453

 

$

2,424

 

$

1,998

 

$

1,624

 

Net income (loss) (2)

 

$

(409

)

$

(2,580

)

$

526

 

$

462

 

$

269

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

(4.38

)

$

(27.75

)

$

6.01

 

$

5.30

 

$

3.10

 

Diluted

 

$

(4.38

)

$

(27.75

)

$

6.00

 

$

5.29

 

$

3.09

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash dividends declared per share

 

$

0.32

 

$

0.64

 

$

0.64

 

$

0.56

 

$

0.48

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flow data:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

599

 

$

692

 

$

1,619

 

$

1,324

 

$

1,193

 

Net cash used by investing activities

 

$

(692

)

$

(1,009

)

$

(1,740

)

$

(1,531

)

$

(1,415

)

Net cash (used) provided by financing activities

 

$

(33

)

$

691

 

$

522

 

$

142

 

$

289

 

 

 

December 31,

 

 

 

2016

 

2015

 

2014

 

2013

 

2012

 

 

 

(in millions, except proved reserves amounts)

 

Balance sheet data:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

653

 

$

779

 

$

406

 

$

5

 

$

70

 

Oil and gas properties, net (2)

 

$

2,354

 

$

2,741

 

$

6,638

 

$

5,669

 

$

4,871

 

Goodwill

 

$

620

 

$

620

 

$

620

 

$

620

 

$

620

 

Total assets (2) (3)

 

$

4,238

 

$

4,708

 

$

8,443

 

$

6,947

 

$

6,160

 

Deferred income tax (asset) liability

 

$

(56

)

$

157

 

$

1,657

 

$

1,351

 

$

1,072

 

Long-term obligations

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (principal)

 

$

1,500

 

$

1,500

 

$

1,500

 

$

924

 

$

750

 

Other

 

$

184

 

$

197

 

$

194

 

$

164

 

$

313

 

Stockholders’ equity

 

$

2,043

 

$

2,458

 

$

4,332

 

$

3,834

 

$

3,390

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

105,878

 

107,798

 

118,992

 

108,533

 

77,921

 

Gas (Bcf)

 

1,471

 

1,517

 

1,667

 

1,294

 

1,252

 

NGL (MBbls)

 

130,633

 

124,277

 

125,273

 

92,044

 

89,909

 

Total (Bcfe)

 

2,890

 

2,909

 

3,132

 

2,497

 

2,259

 


 Years Ended December 31,
 2018 2017 2016 2015 2014
 (in thousands, except per share amounts)
Operating results: 
  
  
  
  
Oil, gas, and NGL sales$2,297,645
 $1,874,003
 $1,221,218
 $1,417,538
 $2,372,829
Total revenues (1)$2,339,017
 $1,918,249
 $1,257,345
 $1,452,619
 $2,424,176
Net income (loss) (2)$791,851
 $494,329
 $(408,803) $(2,579,604) $526,498
          
Earnings (loss) per share to common stockholders: 
  
  
  
  
Basic$8.32
 $5.19
 $(4.38) $(27.75) $6.01
Diluted$8.32
 $5.19
 $(4.38) $(27.75) $6.00
Cash dividends declared per share$0.68
 $0.32
 $0.32
 $0.64
 $0.64
          
Cash flow data: 
  
  
  
  
Net cash provided by operating activities (3)$1,550,994
 $1,096,564
 $625,849
 $725,728
 $1,632,925
Net cash used by investing activities$(1,085,618) $(1,265,897) $(692,410) $(1,008,605) $(1,740,467)
Net cash (used) provided by financing activities (3)$(65,244) $(83,009) $(59,945) $656,397
 $508,873
 December 31,
 2018 2017 2016 2015 2014
 (in thousands, except proved reserves amounts)
Balance sheet data: 
  
  
  
  
Cash and cash equivalents$800,666
 $400,534
 $652,876
 $779,382
 $405,862
Oil and gas properties, net (2)$3,715,330
 $3,241,530
 $2,354,267
 $2,741,282
 $6,637,796
Goodwill$620,232
 $620,232
 $620,232
 $620,232
 $620,232
Total assets (2) (4)$6,062,084
 $5,042,639
 $4,237,724
 $4,708,422
 $8,442,554
Deferred income tax liability (asset)$334,473
 $101,618
 $(55,835) $157,162
 $1,657,456
Long-term obligations: 
  
  
  
  
Long-term debt (principal)$1,500,000
 $1,500,000
 $1,500,000
 $1,500,000
 $1,500,000
Other$200,564
 $206,249
 $184,444
 $197,216
 $193,629
Stockholders’ equity$3,329,786
 $2,568,278
 $2,042,989
 $2,458,357
 $4,331,966
          
Proved Reserves: 
  
  
  
  
Oil (MBbls)146,538
 137,238
 105,878
 107,798
 118,992
Gas (Bcf)1,591
 1,608
 1,471
 1,517
 1,667
NGL (MBbls)179,436
 153,860
 130,633
 124,277
 125,273
Total (MBOE)591,195
 559,037
 481,748
 484,901
 522,054

(1)         Prior to 2014, our average realized prices

(1)
Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating in the statement of operations under prior accounting standards are now reflected

36
Table of Contents


as deductions from revenue. The adoption of ASC 606 reduced revenue for gas and NGLs were net of certain processing fees.  Beginning in 2014, these fees were no longer netted against realized prices, but were included in “Transportation, processing and other operating” costs.  The effect of this change in 2014 was that total revenue was $51.4 million higher with an offsetting increase in total transportation, processing and other operating costs.  This change had no effect on operating income.  Periods prior to 2014 were not reclassified to reflect this change in accounting treatment as it was impracticable.

(2)         During 2016, 2015, 2013 and 2012 we recorded non-cash full cost ceiling test impairments to our oil and gas properties totaling $757.7 million ($481.4 million, net of tax), $4.0 billion ($2.6 billion, net of tax), $190.2 million ($120.8 million, net of tax), and $134.1 million ($85.2 million, net of tax), respectively.

(3)         Atthe year ended December 31, 2015, we adopted new guidance which requires debt issuance costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction2018 by $44.8 million from the carrying amount of the related debt liability rather than as an asset. Such costs were previously recorded as deferred assets.  Prior periodswhat it would have been adjusted to conform to this guidance.

under prior accounting standards.

(2)During 2016 and 2015, we recorded non-cash full cost ceiling test impairments of our oil and gas properties totaling $757.7 million ($481.4 million, net of tax) and $4.03 billion ($2.56 billion, net of tax), respectively.
(3)
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017. Pursuant to ASU 2016-09, we adjusted the statements of cash flows for all prior periods presented. For the years ended December 31, 2016, 2015, and 2014, we decreased cash outflows for operating activities and cash inflows for financing activities by $26.6 million, $34.2 million, and $13.6 million, respectively, for the payment of employee tax withholdings on the net settlement of equity-classified awards and for excess tax benefits, as applicable.
(4)At December 31, 2015, we adopted new accounting guidance which requires debt issuance costs (except for those related to revolving credit facilities) to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. Such costs were previously recorded as deferred assets. Prior periods have been adjusted to conform to this guidance.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements included in Item 8 of this report and also with “Risk Factors”RISK FACTORS in Item 1A of this report. This discussion also includes forward-looking statements. Refer to “Cautionary Information about Forward-Looking Statements”CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report for important information about these types of statements.

As discussed in the Explanatory Note in this Form 10-K/A and in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K/A, we have corrected our Consolidated Financial Statements and related disclosures for the years ended December 31, 2016, 2015 and 2014. The following discussion and analysis of our financial condition and results of operations incorporates the corrected amounts. No attempt has been made to update other disclosures, except as required to reflect the effects of the corrections.

OVERVIEW

Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, Texas, and New Mexico. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.


Our principal business objective is to profitably growincrease shareholder value through the profitable long-term growth of our proved reserves and production while seeking to minimize our impact on the communities in which we operate for the long-term benefit of our stockholders through a balanced and abundant drilling inventory.long-term. Our strategy centers on maximizing cash flow from producing properties and profitably reinvestingso that cash flowwe can reinvest in exploration and development activities.opportunities and provide cash returns to shareholders through increasing dividends. We consider property acquisitions, dispositionsmerger and occasional mergers toacquisition opportunities that enhance our competitive position and we occasionally divest non-core assets.

On August 31, 2018, we closed on the divestiture of oil and gas properties principally located in Ward County, Texas for a sales price of $544.5 million, as adjusted to reflect the resolution of all asserted defects. As of December 31, 2018, we have received $534.6 million in net cash proceeds as adjusted for customary closing adjustments to reflect an effective date of April 1, 2018 and transaction costs. Final settlement, which will reflect customary post-closing adjustments, is scheduled to occur by the end of first quarter 2019. This divestiture did not significantly alter the relationship between capitalized costs and proved reserves, therefore, in accordance with the full cost method of accounting, no gain or loss was recognized. This divestiture is part of our continuous portfolio optimization and high-grading of our investment opportunities.

On November 18, 2018, we entered into an agreement and plan of merger to acquire Resolute Energy Corporation (“Resolute”) in a cash and stock transaction valued at a total purchase price of approximately $1.6 billion, including the assumption of Resolute’s long-term debt, which was $710 million as of September 30, 2018. Under the terms of the agreement, Resolute shareholders will have the right to receive 0.3943 shares of Cimarex common stock, $35.00 per share in cash, or a combination of $14.00 per share in cash and 0.2366 shares of Cimarex common stock. The amount of stock and cash is subject to proration for a total stock and cash mix of 60% and 40%, respectively. This pending acquisition will expand Cimarex’s footprint in Reeves County, Texas by 21,100 net acres that are complementary to our existing Reeves County position.

The transaction, which is expected to be completed by the end of the first quarter 2019, is subject to the approval of Resolute shareholders, which includes voting agreements with certain


37
Table of Contents


shareholders that collectively beneficially own approximately 26% of the outstanding Resolute voting power and the satisfaction of certain regulatory approvals and other customary closing conditions.

We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position us to continue to achieve profitable increases in proved reserves and production. Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility.

Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and, occasionalfrom time to time, public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand unpredictable fluctuations in commodity prices.

Market Conditions

The oil and gas industry is cyclical and commodity prices can be volatile.  In the second halffluctuate significantly. We expect this volatility to persist. Commodity prices are affected by many factors outside of 2014, oil prices began a rapid and significant decline as global oil supplies began to outpace demand.  During 2015 and through the first quarter of 2016, global oil supply continued to outpace demand.  While oil prices have been, and will likely remain, erratic, beginningour control, including changes in the second quarter of 2016 and thus far in 2017, realized oil prices have improved.

Due to an imbalance betweenmarket supply and demand, across North America,inventory storage levels, weather conditions, and other factors.

During 2018, as compared to 2017, market prices for domestic naturaloil have improved, while market prices for gas have declined. During 2018, average NYMEX oil and NGLs began to decline duringgas prices were $64.77 per barrel and $3.09 per Mcf, respectively, representing an increase of 27% and a decrease of 1%, respectively, from the third quarter of 2014average NYMEX oil and continued togas prices for 2017. Local market prices for oil and gas can be weak through the first quarter of 2016.  Beginning lateimpacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. Gas production growth and pipeline constraints in the second quarterPermian Basin and Mid-Continent region and oil production growth and pipeline constraints in the Permian Basin have resulted in higher basis differentials and, therefore, lower realized prices. The average prices per barrel of 2016, pricesoil and Mcf of gas that we realized were less than the WTI Cushing and Henry Hub indices by the amounts shown in the table below for natural gas and NGLs strengthened, but continuethe periods indicated.
  Average Price Differentials
2018 Year Fourth
Quarter		 Third
Quarter		 Second
Quarter		 First
Quarter
Permian Basin oil $9.82
 $11.64
 $14.34
 $8.05
 $3.12
Mid-Continent oil $2.46
 $2.33
 $1.08
 $2.18
 $2.34
Permian Basin gas $1.40
 $2.21
 $1.25
 $1.31
 $0.78
Mid-Continent gas $0.86
 $0.83
 $0.94
 $1.03
 $0.70
           
2017          
Permian Basin oil $3.98
 $3.99
 $4.06
 $4.14
 $3.96
Mid-Continent oil $3.52
 $2.65
 $2.99
 $4.19
 $5.10
Permian Basin gas $0.39
 $0.37
 $0.29
 $0.42
 $0.43
Mid-Continent gas $0.33
 $0.33
 $0.38
 $0.34
 $0.23

Pipeline expansion projects in the Permian Basin are expected to fluctuate.

ease capacity constraints as they come online over the next few years, which is reflected in the current futures markets that show narrowing differentials. However, if pipeline constraints remain, higher differentials will persist or potentially worsen. Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and natural gas production. Compared to 2015, our realized oil price for 2016 fell 12% to $38.30 per barrel.  Similarly, our realizedSee price for natural gas dropped 9% to $2.31 per Mcf, while our realized price for NGLs increased 2% to $14.05 per barrel.  SeeRESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.

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

2016


38
Table of Contents


2018 Summary of Operating and Financial Results

Weakness in commodity prices has continued


Total daily production volumes increased 17% to have a significant adverse impact on our results of operations, our balance sheet and the amount of cash flow available221.9 MBOE per day.
Oil volumes increased 18% to invest in exploration67.7 MBbls per day.
Gas volumes increased 10% to 563.9 MMcf per day.
NGL volumes increased 27% to 60.3 MBbls per day.
Total production revenue increased 23% to $2.30 billion.
Year-end proved reserves increased 6% to 591.2 MMBOE, as compared to 559.0 MMBOE at year-end 2017.
Exploration and development activities.

The following is a summary of certain 2016 operating and financial results:

·                  In response to lower commodity prices, we reduced exploration and development expenditures 16% to $734.8 millioncapital investments were $1.57 billion, as compared to $877.0 million in 2015.

·                  Year-over-year average daily production declined 2% to 963.4 MMcfe per day.

·                  During 2016, oil production declined by 12% to 45,158 barrels per day, gas volumes remained relatively flat at 459.6 MMcf per day and NGL volumes rose 8% to 38,797 barrels per day.

·                  Year-over-year production revenues declined 14% to $1.2 billion.

·                  During 2016, non-cash impairments of our oil and gas properties were $757.7 million, down from $4.0$1.28 billion in 2015.

·                  In 2016, we incurred a net loss of $408.8 million ($4.38 per diluted share) compared to a net loss of $2.6 billion ($27.75 per diluted share) in 2015.

·2017.

Cash flow provided by operating activities of $599.2 million was 13% lower than that of the prior year.

·increased 41% to $1.55 billion.

Cash on hand at December 31, 20162018 was $652.9$800.7 million.

·For the year ended December 31, 2018, we had net income of $791.9 million ($8.32 per diluted share) as compared to net income of $494.3 million ($5.19 per diluted share) in 2017. Production revenue in 2018 was positively impacted by increased production volumes across all products as well as increased realized oil and NGL commodity prices. Lower realized gas prices negatively impacted 2018. Year-over-year changes are discussed further in the                   Year-endRESULTS OF OPERATIONS section that follows.
Proved Reserves

Our proved reserves were 2.89 Tcfe compared to 2.91 Tcfe at year-end 2015.

Total debtby region at December 31, 2016 consisted of $1.5 billion of senior notes, with $750 million maturing in 20222018 and $750 million maturing in 2024, unchanged from total debt at December 31, 2015.

2017 were as follows:

 December 31, 2018
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
Permian Basin727,985
 116,378
 96,533
 334,241
Mid-Continent861,440
 29,908
 82,826
 256,307
Other1,896
 252
 77
 647
Total1,591,321
 146,538
 179,436
 591,195
 December 31, 2017
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
Permian Basin573,757
 105,198
 68,530
 269,354
Mid-Continent1,032,695
 31,853
 85,292
 289,261
Other1,183
 187
 38
 422
Total1,607,635
 137,238
 153,860
 559,037
Proved Reserves

 

 

December 31, 2016

 

 

 

Gas

 

Oil

 

NGL

 

Total

 

 

 

(MMcf)

 

(MBbl)

 

(MBbl)

 

(MMcfe)

 

Permian Basin

 

372,371

 

74,295

 

40,977

 

1,064,000

 

Mid-Continent

 

1,095,194

 

31,399

 

89,615

 

1,821,278

 

Other

 

3,855

 

184

 

41

 

5,209

 

Total

 

1,471,420

 

105,878

 

130,633

 

2,890,487

 

 

 

December 31, 2015

 

 

 

Gas

 

Oil

 

NGL

 

Total

 

 

 

(MMcf)

 

(MBbl)

 

(MBbl)

 

(MMcfe)

 

Permian Basin

 

378,516

 

78,482

 

36,598

 

1,069,002

 

Mid-Continent

 

1,134,434

 

29,048

 

87,639

 

1,834,554

 

Other

 

4,002

 

268

 

40

 

5,851

 

Total

 

1,516,952

 

107,798

 

124,277

 

2,909,407

 

Year-end 20162018 proved reserves declined by less than 1%increased approximately 6% to 2.89 Tcfe,591.2 MMBOE, compared to 2.91 Tcfe559.0 MMBOE at year-end 2015.2017. Proved natural gas reserves were 1.471.59 Tcf, proved oil reserves were 0.64 Tcfe,146.5 MMBbls, and proved NGL reserves were 0.78 Tcfe.179.4 MMBbls. Reserves in our Mid-Continent regionthe Permian Basin accounted for 63%57% of our total proved reserves with the majoritynearly all of the remainder in the Permian Basin.

During 2016, we added 324.0 Bcfe of proved reserves through extensions and discoveries, primarily in theour Mid-Continent and Permian Basin, where we added 121.6 Bcfe and 198.7 Bcfe, respectively.  In addition, we had net positive revisions of previous estimates of 19.8 Bcfe.  Revisions were comprised of an increase of 126.2 Bcfe for net positive performance revisions, an increase of 138.5 Bcfe related to lower operating expenses and a decrease of 244.9 Bcfe for negative revisions due to lower commodity prices.region. See SUPPLEMENTAL INFORMATION ON OIL AND GAS INFORMATIONPRODUCING ACTIVITIES (UNAUDITED) in Item 8 of this report for a more detailed discussion regarding year-over-year changes in our proved reserves.


39
Table of Contents


The process of estimating quantities of oil, gas, and NGL reserves is complex. Significant decisions are required in the evaluation of all available geological, geophysical, engineering, and economic data. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures. See Proved Reserves Estimation Procedures in Items 1 and 2 of this report for a discussion of our reserve estimation process and Item 1A.1A RISK FACTORS for, which includes a discussion of factors that affect our proved reserves estimates.


RESULTS OF OPERATIONS

RevenuesEffective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606,

Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following table presents the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:

  Years Ended December 31,
  2018 2017 2016
(in thousands) Pre-
ASC 606 Adoption		 Impact of
ASC 606		 Post-
ASC 606 Adoption		 As Reported As Reported
Oil sales $1,398,813
 $—
 $1,398,813
 $981,646
 $632,934
Gas sales 425,233
 (16,482) 408,751
 516,936
 388,786
NGL sales 518,410
 (28,329) 490,081
 375,421
 199,498
Total oil, gas, and NGL sales $2,342,456
 $(44,811) $2,297,645
 $1,874,003
 $1,221,218
           
Transportation, processing, and other operating costs $245,613
 $(44,811) $200,802
 $231,640
 $190,725

Almost all our revenues are derived from sales of our oil, natural gas, and NGL production. Increases or decreases in our revenue,revenues, profitability, and future production growth are highly dependent on the commodity prices we receive. Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, availability of transportation, seasonality, and geopolitical, and economic factors.

Oil sales contributed 52% See Item 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our totalrevenues to price fluctuations.


2018 Compared to 2017

Revenues

A decrease in realized gas prices as well as the impact of ASC 606, as discussed above, negatively impacted our revenues in 2018 as compared to 2017. However, increases in production revenue for 2016.  Gas sales accounted for 32%volumes and realized oil and NGL prices in 2018 as compared to 2017 more than offset declines in gas sales, contributed 16%.  A $1.00 per barrel change incausing our realized oil price would have resulted in a $16.5revenues to increase by $423.6 million, change in revenues.  A $0.10 per Mcf change in our realized gas price would have resulted in a $16.8 million change in our gas revenues.  A $1.00 per barrel change in our realized NGL price would have changed revenues by $14.2 million.

or 23%, from prior year. The following table shows our production revenues for 2018 and 2017 as well as the change in revenues due to changes in prices and volumes.



40
Table of Contents


  Years Ended
December 31,		     Price / Volume Variance
Production Revenue (in thousands)
 2018 2017 Variance Between
2018 / 2017		 Price Volume Total
Oil sales $1,398,813
 $981,646
 $417,167
 42 % $235,981
 $181,186
 $417,167
Gas sales 408,751
 516,936
 (108,185) (21)% (158,494) 50,309
 (108,185)
NGL sales 490,081
 375,421
 114,660
 31 % 14,736
 99,924
 114,660
  $2,297,645
 $1,874,003
 $423,642
 23 % $92,223
 $331,419
 $423,642
The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. Our realized prices do not include settlementsThe sale of commodity derivative contracts.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Oil Prices ($/Bbl):

 

 

 

 

 

 

 

Average realized sales price

 

$

38.30

 

$

43.38

 

$

83.70

 

Average WTI Midland price

 

$

43.34

 

$

48.39

 

$

86.18

 

Average WTI Cushing price

 

$

43.32

 

$

48.80

 

$

93.01

 

Gas Prices ($/Mcf):

 

 

 

 

 

 

 

Average realized sales price

 

$

2.31

 

$

2.53

 

$

4.43

 

Average Henry Hub price

 

$

2.46

 

$

2.67

 

$

4.43

 

NGL Prices ($/Bbl):

 

 

 

 

 

 

 

Average realized sales price

 

$

14.05

 

$

13.75

 

$

33.14

 

our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. During 2016, 20152018 and 2014, approximately 80%, 84%2017, 77% and 80%78%, respectively, of our oil production was in the Permian Basin with the sale of which is tied to the WTI Midland benchmark price.  The majority of the remaining oil production is from ourremainder in the Mid-Continent region, the sale of which is tied to the WTI Cushing benchmark price.

See RESULTS OF OPERATIONS below for analysis of the impact changes inregion. Our realized prices had ondo not include settlements of commodity derivative contracts.

  Years Ended
December 31,		 Variance Between
2018 / 2017
  2018 2017 
Oil        
Total volume — MBbls 24,710
 20,861
 3,849
 18 %
Total volume — MBbls per day 67.7
 57.2
 10.5
 18 %
Percentage of total production 31% 30%    
Average realized price — per barrel $56.61
 $47.06
 $9.55
 20 %
Average WTI Midland price — per barrel $58.31
 $50.45
 $7.86
 16 %
Average WTI Cushing price — per barrel $64.77
 $50.94
 $13.83
 27 %
         
Gas        
Total volume — MMcf 205,837
 187,468
 18,369
 10 %
Total volume — MMcf per day 563.9
 513.6
 50.3
 10 %
Percentage of total production 42% 45%    
Average realized price — per Mcf $1.99
(1)$2.76
 $(0.77) (28)%
Average Henry Hub price — per Mcf $3.09
 $3.11
 $(0.02) (1)%
         
NGL        
Total volume — MBbls 21,994
 17,374
 4,620
 27 %
Total volume — MBbls per day 60.3
 47.6
 12.7
 27 %
Percentage of total production 27% 25%    
Average realized price — per barrel $22.28
(2)$21.61
 $0.67
 3 %
         
Total        
Total production — MBOE 81,010
 69,479
 11,531
 17 %
Total production — MBOE per day 221.9
 190.4
 31.5
 17 %
Average realized price — per BOE $28.36
(3)$26.97
 $1.39
 5 %

(1)ASC 606 reduced the average realized gas price by $0.08 per Mcf for the year ended December 31, 2018.
(2)ASC 606 reduced the average realized NGL price by $1.29 per barrel for the year ended December 31, 2018.
(3)ASC 606 reduced the average realized total price by $0.56 per BOE for the year ended December 31, 2018.

Our 2018 daily production volumes were 221.9 MBOE, a 17% increase from 2017. This increase is the result of increased drilling and completion activity during 2018 as compared to 2017. See Production Volumes, Prices, and Costs and Exploration and Development Overview in Items 1 and 2 of this report for production information by region and a discussion of our year-over-year revenues.drilling activities.


41
Table of Contents


Other Revenues
We transport, process, and market some third-party gas that is associated with our equity gas. We market and sell gas for other working interest owners under short term agreements and may earn a fee for such services. The table below reflects income from third-party gas gathering and processing and our net marketing margin for marketing third-party gas.
  Years Ended December 31, Variance
Between
2018 / 2017
Gas Gathering and Marketing (in thousands):
 2018 2017 
Gas gathering and other $41,180
 $43,751
 $(2,571)
Gas marketing $192
 $495
 $(303)
Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, and gathering rate charges. The decreases from 2017 are primarily due to lower rates and decreases in prices and volumes.
Operating costsCosts and expenses

Expenses


Costs associated with producing oil and natural gas are substantial. SomeAmong other factors, some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own. Atown, some depend on the endprices charged by service companies, and some fluctuate based on a combination of 2016, we owned interests in 10,279 gross productive wells.

We use the full cost method of accounting for our oil and gas operations.  Accounting rules require us to perform a quarterly ceiling test calculation to test our capitalized oil and gas property costs for possible impairment.  If the net capitalized cost of our oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of (i) the present value discounted at 10% of estimated future net cash flows from proved reserves, (ii) the cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (iv) all related tax effects.  Estimated future net cash flows are determined by proved reserve quantities and commodity prices net offoregoing.


Total operating costs and capital expenditures.

We recognized ceiling test impairmentsexpenses of $1.29 billion in each quarter of 2015 totaling $4.02018 were 11% higher than the $1.17 billion ($2.6 billion, net of tax).  In the first three quarters of 2016 we recognized ceiling test impairments totaling $757.7 million ($481.4 million, net of tax).incurred in 2017. The impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the estimated future net cash flows from proved reserves.

At December 31, 2016, the calculated valueprimary drivers of the ceiling limitation exceededincrease were depletion, taxes other than income, production expense, and other operating expense, with these being partially offset by lower transportation and processing and increased gains on derivative instruments. The following table shows our operating costs and expenses for the carrying valueyears indicated and a discussion of year-over-year differences follows.

  Years Ended December 31, 
Variance
Between
2018 / 2017
 Per BOE
Operating Costs and Expenses (in thousands, except per BOE)
 2018 2017  2018 2017
Depreciation, depletion, and amortization $590,473
 $446,031
 $144,442
 $7.29
 $6.42
Asset retirement obligation 7,142
 15,624
 (8,482) $0.09
 $0.22
Production 293,213
 262,180
 31,033
 $3.62
 $3.77
Transportation, processing, and other operating 200,802
 231,640
 (30,838) $2.48
 $3.33
Gas gathering and other 41,964
 35,840
 6,124
 $0.52
 $0.52
Taxes other than income 125,169
 89,864
 35,305
 $1.55
 $1.29
General and administrative 80,850
 79,996
 854
 $1.00
 $1.15
Stock compensation 22,895
 26,256
 (3,361) $0.28
 $0.38
Gain on derivative instruments, net (85,959) (21,210) (64,749) N/A
 N/A
Other operating expense, net 15,500
 1,314
 14,186
 N/A
 N/A
  $1,292,049
 $1,167,535
 $124,514
  
  
Depreciation, Depletion, and Amortization
Depletion of our oil and gas properties subject to the test, and no impairment was necessary. However, a decline of approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment.  Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation.  In addition, other factors that also impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense and all related tax effects.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties.  The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income (loss) and various components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date.

Depletion, depreciation and amortization (DD&A) of our proved oil and gasproducing 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 sales of production.  Therefore, fluctuations in oil and gas prices will impact the level of proved reserves used in the calculation.  Higher prices generally have the effect of increasing reserves, which reduces depletion expense.  Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense.  The cost of replacing production also impacts our DD&A rate.depletion expense.  In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved,


42
Table of Contents


and impairments of oil and gas properties will also impact depletion expense. While the increase in oil prices has more than offset the decrease in gas prices during 2018 as compared to 2017, thus increasing our reserves, the increase in production combined with our ongoing exploration and development capital expenditures throughout 2018 have resulted in an overall increase in depletion expense.
Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years.  Depreciation, depletion, and amortization (“DD&A&A”) consisted of the following for the years indicated:
  Years Ended December 31, Variance
Between
2018 / 2017		 Per BOE
DD&A Expense (in thousands, except per BOE)
 2018 2017  2018 2017
Depletion $538,919
 $399,328
 $139,591
 $6.65
 $5.75
Depreciation 51,554
 46,703
 4,851
 0.64
 0.67
  $590,473
 $446,031
 $144,442
 $7.29
 $6.42
Asset Retirement Obligation
Asset retirement obligation expense is calculated quarterly beforetypically primarily comprised of accretion expense. In periods subsequent to the ceiling test impairment calculation.initial measurement of an asset retirement obligation liability at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. Also included in asset retirement obligation expense are gains and losses recognized on the settlement of asset retirement obligation liabilities.
Asset retirement obligation expense decreased 54%, or $8.5 million, compared to 2017. The impairmentsexpense in 2017 included $10.5 million for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. In January 2018, the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to these properties. Our estimate of our oilliability may change as we refine our understanding of the extent of our obligations under the orders from BSEE and gas properties, discussed above, resulted in lower DD&A rates in each quarter following an impairment.

obtain additional information on decommissioning costs.

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

  Production expense consists of lease operating expense and workover expense as follows:

  Years Ended December 31, Variance
Between
2018 / 2017		 Per BOE
Production Expense (in thousands, except per BOE)
 2018 2017  2018 2017
Lease operating expense $241,885
 $215,148
 $26,737
 $2.99
 $3.10
Workover expense 51,328
 47,032
 4,296
 0.63
 0.67
  $293,213
 $262,180
 $31,033
 $3.62
 $3.77

Through efficiency gains and increasing daily production by 17% during 2018 as compared to 2017, we reduced our per unit lease operating expense by 4% between these two periods. On an absolute basis, lease operating expense in 2018 increased 12%, or $26.7 million, compared to 2017.  The increase was primarily caused by increases in the following costs: (i) equipment rental, primarily additional compressors, (ii) saltwater disposal costs, due to increased water volumes, (iii) tank battery and processing equipment and maintenance, primarily due to the addition of new wells, (iv) contract pumpers, (v) environmental compliance, primarily emissions-related, (vi) electricity, primarily due to the addition of new wells, and (vii) chemicals and treating, due to increased water volumes.

43
Table of Contents


Workover expense increased 9%, or $4.3 million, during 2018 as compared to 2017. During 2018, we had more workover projects than we did in 2017. During 2018, we incurred the majority of our workover expense on major well workovers and artificial lift conversions, with artificial lift conversions being the largest increase from 2017. Partially offsetting the increase in expense on workover projects was the receipt of insurance proceeds during 2018 related to a previous flood and line rupture. Remediation and repairs for these events were charged to workover expense at the time incurred. Generally, workover costs will fluctuate based on the amount of maintenance and remedial activity required during the period.
Transportation, Processing, and Other Operating
Transportation, processing, and other operating costs principally consist of expenditures to prepare and transport production from the wellhead, together with gasincluding gathering, fuel, compression, and processing costs and costs to transport production to a specified sales point.costs.  Costs vary by region and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

Transportation, processing, and other operating costs in 2018 were 13%, or $30.8 million, lower than in 2017. This decrease is due to our adoption of ASC 606 effective January 1, 2018, whereby certain transportation and processing costs are now reclassified out of transportation, processing, and other operating costs and are treated as a deduction from revenue. The adoption of ASC 606 reduced Transportation, processing, and other operating costs by $44.8 million in 2018. The reduction was partially offset by increased costs due to increased production volumes. See Note 1 to the Consolidated Financial Statements for additional information regarding the adoption of ASC 606.
Gas Gathering and Other
Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs and operating and maintenance expenses.  Gas gathering and other in 2018 was 17%, or $6.1 million, higher than in 2017.  The increase was primarily due to overall increases in operating costs partially offset by lower product costs associated with processing third-party production due to lower volumes and prices.
Taxes Other than Income
Taxes other than income consist of production (or severance) taxes, ad valorem taxes, and other taxes.  State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production and ad valorem taxes being based on the value of properties.  Production taxes make up the majority of this expense for us, with revenue-based production taxes being the largest component of these taxes.  In 2018, taxes other than income increased 39%, or $35.3 million, from 2017.  This increase is primarily due to the increase in revenue in 2018 as well as due to increased ad valorem taxes in 2018 due to higher assessed valuations and new wells. Both years include credits for tax refunds. We had $15.7 million in credits in 2018, primarily for Texas marketing cost deduction refunds. We had $9.6 million in credits in 2017, primarily for Texas high-cost gas well refunds. Taxes other than income were 5.4% and 4.8% of production revenues for 2018 and 2017, respectively.
General and Administrative
General and administrative expenses consist(“G&A”) expense consists primarily of salaries and related benefits, office rent, legal and consultantsconsulting fees, systems costs, and other administrative costs incurred in our offices and not directly associated with exploration, development or production activities.incurred.  Our G&A expense is reported net of amounts reimbursed to us by working interest owners of the oil and gas properties we operate and net of amounts capitalized pursuant to the full cost method of accounting.

A discussion  The amount of changes in operating costsexpense capitalized varies and expenses is included in RESULTS OF OPERATIONS, below.

RESULTS OF OPERATIONS

2016 compared to 2015

Fordepends on whether the year ended December 31, 2016, we had a net losscost incurred can be directly identified with acquisition, exploration, and development activities. The percentage of $408.8 million ($4.38 per diluted share), down from a net loss of $2.6 billion ($27.75 per diluted share) in 2015.  Production revenues in 2016gross G&A capitalized was 47% and 2015 were adversely affected by low realized commodity prices, which also brought about impairments of49% during 2018 and 2017, respectively. The table below shows our oil and gas properties and net losses for each year. Although production revenue in 2016 was lower than 2015, the decrease was more than offset by lower impairment, DDG&A and other operating costs in 2016. Year-over-year changes are discussed further in the analysis that follows.

 

 

 

 

 

 

Percent

 

 

 

 

 

 

 

 

 

Years Ended

 

Change

 

 

 

 

 

 

 

 

 

December 31,

 

Between

 

Price / Volume Change

 

Production Revenue

 

2016

 

2015

 

2016 / 2015

 

Price

 

Volume

 

Total

 

(in thousands or as indicated)

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

632,934

 

$

809,664

 

(22

)%

$

(83,962

)

$

(92,768

)

$

(176,730

)

Gas sales

 

388,786

 

428,227

 

(9

)%

(37,010

)

(2,431

)

(39,441

)

NGL sales

 

199,498

 

179,647

 

11

%

4,260

 

15,591

 

19,851

 

Total production revenue

 

$

1,221,218

 

$

1,417,538

 

(14

)%

$

(116,712

)

$

(79,608

)

$

(196,320

)

Total oil volume — MBbls

 

16,528

 

18,663

 

(11

)%

 

 

 

 

 

 

Oil volume — barrels per day

 

45,158

 

51,132

 

(12

)%

 

 

 

 

 

 

Oil percentage of total production

 

28

%

31

%

 

 

 

 

 

 

 

 

Average oil price — per barrel

 

$

38.30

 

$

43.38

 

(12

)%

 

 

 

 

 

 

Total gas volume — MMcf

 

168,227

 

168,987

 

0

%

 

 

 

 

 

 

Gas volume — MMcf per day

 

459.6

 

463.0

 

(1

)%

 

 

 

 

 

 

Gas percentage of total production

 

48

%

47

%

 

 

 

 

 

 

 

 

Average gas price — per Mcf

 

$

2.31

 

$

2.53

 

(9

)%

 

 

 

 

 

 

Total NGL volume — MBbls

 

14,200

 

13,063

 

9

%

 

 

 

 

 

 

NGL volume — barrels per day

 

38,797

 

35,789

 

8

%

 

 

 

 

 

 

NGL percentage of total production

 

24

%

22

%

 

 

 

 

 

 

 

 

Average NGL price — per barrel

 

$

14.05

 

$

13.75

 

2

%

 

 

 

 

 

 

Total production — MMcfe

 

352,591

 

359,343

 

(2

)%

 

 

 

 

 

 

Total production — MMcfe per day

 

963.4

 

984.5

 

(2

)%

 

 

 

 

 

 

As reflected in the table above, our 2016 production revenue was 14% lower than that of 2015.  Lower realized prices and production volumes for oil and gas were only partially offset by higher average realized prices and production volumes for NGLs.

Our 2016 aggregate production volumes were 352.6 Bcfe, a 2% decrease from 2015.  Production volumes in 2016 were comprised of 48% natural gas, 28% oil and 24% NGL. In 2015, aggregate production volumes of 359.3 Bcfe were made up of 47% natural gas, 31% oil and 22% NGL. See Production Volumes, Prices, and Costs and Exploration and Development Overview in Items 1 and 2 of this report for production information by region and a discussion of our drilling activities.  See Revenues above, for information regarding realized prices.

costs.

  Years Ended December 31, Variance
Between
2018 / 2017
General and Administrative Expense (in thousands):
 2018 2017 
Gross G&A $152,827
 $156,389
 $(3,562)
Less amounts capitalized to oil and gas properties (71,977) (76,393) 4,416
G&A expense $80,850
 $79,996
 $854

44


Table of Contents

Other revenues

We sometimes transport, process and market third-party gas that is associated with our equity gas. The table below reflects income from third-party gas gathering and processing and our net marketing margin (revenues less purchases) for marketing third-party gas.  We market and sell natural gas for working interest owners under short term sales and supply agreements and may earn a fee for such services.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

Gas Gathering and Marketing (in thousands):

 

 

 

 

 

Gas gathering and other revenues

 

$

36,033

 

$

34,688

 

Gas marketing revenues, net of related costs

 

$

94

 

$

393

 

Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices and gathering rate charges.

Analysis of operating costs and expenses

Total operating costs and expenses of $1.8 billion in 2016 were 67% lower than $5.5 billion incurred in 2015.  Most of the decrease resulted from lower ceiling test impairments of our oil and gas properties and lower DD&A expense.  See Operating costs and expenses above for a discussion of the ceiling limitation and DD&A calculations. Analyses of year-over-year differences are discussed below.

 

 

 

 

 

 

Variance

 

 

 

 

 

 

 

Years Ended December 31,

 

Between

 

Per Mcfe

 

Operating Costs and Expenses

 

2016

 

2015

 

2016 / 2015

 

2016

 

2015

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

$

757,670

 

$

4,033,295

 

$

(3,275,625

)

N/A

 

N/A

 

DD&A

 

392,348

 

731,460

 

(339,112

)

$

1.11

 

$

2.04

 

Asset retirement obligation

 

7,828

 

9,121

 

(1,293

)

$

0.02

 

$

0.03

 

Production

 

232,002

 

299,374

 

(67,372

)

$

0.66

 

$

0.83

 

Transportation, processing and other operating

 

190,725

 

182,362

 

8,363

 

$

0.54

 

$

0.51

 

Gas gathering and other

 

31,785

 

38,138

 

(6,353

)

$

0.09

 

$

0.11

 

Taxes other than income

 

61,946

 

84,764

 

(22,818

)

$

0.18

 

$

0.24

 

General and administrative

 

73,901

 

74,688

 

(787

)

$

0.21

 

$

0.21

 

Stock compensation

 

24,523

 

19,559

 

4,964

 

$

0.07

 

$

0.05

 

(Gain) loss on derivative instruments, net

 

55,749

 

(11,246

)

66,995

 

N/A

 

N/A

 

Other operating (income) expense, net

 

755

 

856

 

(101

)

N/A

 

N/A

 

 

 

$

1,829,232

 

$

5,462,371

 

$

(3,633,139

)

 

 

 

 

DD&A expense in 2016 decreased 46% compared to 2015. The impairments of our oil and gas properties discussed above resulted in lower DD&A rates in each quarter following an impairment.  DD&A is calculated quarterly before the ceiling test impairment calculation.  We did not incur a ceiling test impairment in the fourth quarter of 2016.  Our 2017 DD&A rate will likely fluctuate depending on the per-unit cost of adding new proved reserves and the average trailing twelve-month commodity prices to be utilized in the DD&A calculations.

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

 

 

 

 

 

 

Variance

 

 

 

 

 

 

 

Years Ended December 31,

 

Between

 

Per Mcfe

 

(in thousands)

 

2016

 

2015

 

2016 / 2015

 

2016

 

2015

 

Lease operating expense

 

$

189,291

 

$

249,744

 

$

(60,453

)

$

0.54

 

$

0.70

 

Workover expense

 

42,711

 

49,630

 

(6,919

)

0.12

 

0.13

 

 

 

$

232,002

 

$

299,374

 

$

(67,372

)

$

0.66

 

$

0.83

 

Lease operating expense in 2016 declined 24% compared to 2015.  In 2016, we incurred lower salt water disposal costs due to implementation of operational efficiencies as well as lower costs associated with labor, rental equipment and property divestitures.

Workover expense decreased by 14% in 2016 compared to 2015.  Generally, these costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

Our 2016 year-over-year transportation, processing and other operating costs were 5% higher than those of 2015. These costs will vary by product type and region.  The increase in 2016 is primarily a result of more gas production and higher fees associated with our Mid-Continent region.

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs, operating and maintenance expenses.  The 17% year-over-year decrease is primarily attributable to higher repair and maintenance activities occurring in 2015.

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based production and severance taxes are the largest components of these taxes.  The 27% decrease in 2016 taxes is a result of lower production revenues due to lower realized commodity prices and lower production volumes.

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

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2016

 

2015

 

2016 / 2015

 

G&A capitalized to oil and gas properties

 

$

72,531

 

$

58,332

 

$

14,199

 

G&A expense

 

73,901

 

74,688

 

(787

)

 

 

$

146,432

 

$

133,020

 

$

13,412

 

During 2016, aggregate G&A increased 10% compared to 2015.  The year-over-year increase in aggregate G&A results from a combination of higher accruals in 2016 for short-term incentive based compensation together with severance payments in connection with a voluntary early retirement incentive program, which were partially offset by lower salaries and wages and lower corporate contributions and consulting fees.



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

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2016

 

2015

 

2016 / 2015

 

Restricted stock awards

 

 

 

 

 

 

 

Performance stock awards

 

$

24,183

 

$

18,991

 

$

5,192

 

Service-based stock awards

 

18,391

 

14,547

 

3,844

 

 

 

42,574

 

33,538

 

9,036

 

Stock option awards

 

2,565

 

2,803

 

(238

)

 

 

45,139

 

36,341

 

8,798

 

Less amounts capitalized

 

(20,616

)

(16,782

)

(3,834

)

Stock compensation

 

$

24,523

 

$

19,559

 

$

4,964

 

Expense associated with

  Years Ended December 31, Variance
Between
2018 / 2017
Stock Compensation Expense (in thousands):
 2018 2017 
Restricted stock awards:  
  
  
Performance stock awards $23,083
 $26,020
 $(2,937)
Service-based stock awards 20,385
 19,746
 639
  43,468
 45,766
 (2,298)
Stock option awards 2,456
 2,599
 (143)
Total stock compensation cost 45,924
 48,365
 (2,441)
Less amounts capitalized to oil and gas properties (23,029) (22,109) (920)
Stock compensation expense $22,895
 $26,256
 $(3,361)
Periodic stock compensation expense will fluctuate based on the grant-dategrant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The increasedecrease in 2016total stock compensation cost in 2018 as compared to 2017 is primarily relateddue to performance awards grantedstock award forfeitures during the second quarter 2018. Our accounting policy is to account for forfeitures in December 2015, a portion of which were amortized during 2016, forfeiture rate adjustmentscompensation cost when they occur, therefore, all the previously recognized expense on the service-based stock awards and accelerationforfeited award is reversed at the time of expenseforfeiture.
Gain on a portion of service-based awards for employees who participated in a voluntary early retirement incentive program.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.  See Note 6 to the Consolidated Financial Statements in Item 8 of this report for further discussion regarding our stock-based compensation.

Derivative Instruments, Net

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly settlementcash settlements (if any) of the instruments.  We have chosenelected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments.  Therefore,Consequently, changes in the fair value of our derivative instruments and cash settlements on the contractsinstruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.

  Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows. The following table presents the aggregate net (gain) loss from settlements and changes in the fair valuecomponents of our derivative contracts and the (gains) losses from cash settlements included in the aggregate gain (loss)Gain on derivative instruments, net.net for the years indicated.  See Note 4 to the Consolidated Financial Statements in Item 8 of this report for further detailsadditional information regarding our derivative instruments.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

(Gain) loss on derivative instruments, net

 

$

55,749

 

$

(11,246

)

Settlement (gains) losses

 

$

(7,437

)

$

—

 

  Years Ended December 31, 
Variance
Between
2018 / 2017
Gain on Derivative Instruments, Net (in thousands):
 2018 2017 
Decrease (increase) in fair value of derivative instruments, net:  
  
  
Gas contracts $15,742
 $(40,226) $55,968
Oil contracts (126,130) 17,383
 (143,513)
  (110,388) (22,843) (87,545)
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (13,794) (4,557) (9,237)
Oil contracts 38,223
 6,190
 32,033
  24,429
 1,633
 22,796
Gain on derivative instruments, net $(85,959) $(21,210) $(64,749)
Other (income)Operating Expense, Net
Other operating expense, net increased $14.2 million in 2018 as compared to 2017. This expense is comprised primarily of litigation settlements and allowance for doubtful accounts adjustments. The increase in expense

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2016

 

2015

 

2016 / 2015

 

Interest expense

 

$

83,272

 

$

85,746

 

$

(2,474

)

Capitalized interest

 

(21,248

)

(30,589

)

9,341

 

Other, net

 

(10,707

)

(13,576

)

2,869

 

 

 

$

51,317

 

$

41,581

 

$

9,736

 

in 2018 is due to a $14.2 million increase in litigation settlements.


45
Table of Contents


Other Income and Expense
  Years Ended December 31, Variance
Between
2018 / 2017
Other Income and Expense (in thousands):
 2018 2017 
Interest expense $68,224
 $74,821
 $(6,597)
Capitalized interest (20,855) (22,948) 2,093
Loss on early extinguishment of debt —
 28,187
 (28,187)
Other, net (22,908) (11,342) (11,566)
  $24,461
 $68,718
 $(44,257)
The majority of our interest expense relates to interest on debt andour senior unsecured notes. Also included in interest expense is the amortization of financing costs.debt issuance costs and discount, as well as miscellaneous interest expense. See LIQUIDITY AND CAPITAL RESOURCES Long-Term Debt below for further information regarding our debt. The decrease in interest expense in 2018 as compared to 2017 is due to the completion of a tender offer and redemption of $750 million 5.875% senior notes and the issuance of $750 million 3.90% senior notes, both of which occurred during the second quarter of 2017. The $28.2 million loss on early extinguishment of debt incurred during 2017 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.

We capitalize interest on the capitalized cost of unproved properties,non-producing leasehold costs, the in-progress costs of drilling and completing wells, and constructing qualifiedmidstream assets.  Capitalized interest will fluctuate based on our current rate of

interestthe rates applicable to borrowings outstanding during the period and the amount of costs on whichsubject to interest is calculated.capitalized. The 31% decreaseamount of costs subject to interest capitalization was lower in year-over-year2018 as compared to 2017, thus reducing our capitalized expense resulted frominterest in 2018. Also contributing to lower capitalized interest in 2018 was a lower average unprovedinterest rate on borrowings outstanding due to the replacement of our 5.875% notes with 3.90% notes in the second quarter of 2017.

Other, net includes interest income of $11.1 million and $5.4 million in 2018 and 2017, respectively. The increase in interest income in 2018 is primarily due to the cash proceeds we received from our Ward County property costsdivestiture at the end of August 2018, which we subsequently invested the majority of in 2016.

Componentsshort-term interest-bearing accounts. Additionally, interest rates have increased throughout 2017 and 2018. Other components of “Other, net” consist ofOther, net include miscellaneous income and expense items that will vary from period to period, including gain or loss onrelated to the sale or value of oil and gas well equipment and supplies, gain or loss on miscellaneous fixed asset sales, and income and expense associated with other non-operating activities, miscellaneous asset sales and interest income.  The 21% decrease in 2016 income was primarily due to lower net gains on transactions related to oil and gas well equipment and supplies.

activities.

Income tax expense

Tax Expense (Benefit)

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

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

Current tax (benefit) expense

 

$

(1,115

)

$

14,710

 

Deferred tax benefit

 

(213,286

)

(1,486,439

)

 

 

$

(214,401

)

$

(1,471,729

)

Combined federal and state effective income tax rate

 

34.4

%

36.3

%

  Years Ended December 31, Variance
Between
2018 / 2017
Income Tax Expense (Benefit) (in thousands):
 2018 2017 
Current tax benefit $(2,624) $(2,812) $188
Deferred tax expense 233,280
 190,479
 42,801
  $230,656
 $187,667
 $42,989
       
Combined federal and state effective income tax rate 22.6% 27.5%  

On December 22, 2017, the United States enacted H.R.1 (Public Law 115-97), commonly referred to as the Tax Cuts and Jobs Act or U.S. Tax Reform. H.R.1, among other things, includes changes to U.S. federal tax rates, imposes new limitations on the utilization of net operating losses and the deductibility of interest and executive compensation, allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. We remeasured the deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2017 and, as a result of this remeasurement, we recorded an income tax benefit of $61.1 million and a corresponding $61.1 million decrease in the net deferred tax liabilities as of December 31, 2017. We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. During 2018, no other adjustments were made. As a result of H.R.1, we expect our effective

46
Table of Contents


tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected.
Our combined federal and state effective tax rates, as shown above, differ from the statutory rate of 35% primarily due to state income taxes, non-deductible expenses, revisions, and revisions.the impact of changes in tax law. See Note 9 to the Consolidated Financial Statements in Item 8 of this report for further information regarding our income taxes.

RESULTS OF OPERATIONS

2015 compared


2017 Compared to 2014

2016

Summary

For the year ended December 31, 2015,2017, we had net income of $494.3 million ($5.19 per diluted share), up from a net loss of $2.6 billion$408.8 million ($27.754.38 per diluted share), compared to net income of $526.5 million ($6.00 per diluted share) for 2014.  The net loss in 20152016. Production revenue in 2017 was primarily a result of lowerpositively impacted by increased realized commodity prices which also brought aboutand production volumes. Lower commodity prices negatively impacted 2016, including resulting in $757.7 million of impairments of our oil and gas properties.properties in that year. Year-over-year changes are discussed further inas follows. Also refer to the analysis that follows.

 

 

 

 

 

 

Percent

 

 

 

 

 

 

 

 

 

Years Ended

 

Change

 

 

 

 

 

 

 

 

 

December 31,

 

Between

 

Price / Volume Change

 

Production Revenue

 

2015

 

2014

 

2015 / 2014

 

Price

 

Volume

 

Total

 

(in thousands or as indicated)

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

809,664

 

$

1,308,958

 

(38

)%

$

(752,492

)

$

253,198

 

$

(499,294

)

Gas sales

 

428,227

 

687,930

 

(38

)%

(321,075

)

61,372

 

(259,703

)

NGL sales

 

179,647

 

375,941

 

(52

)%

(253,292

)

56,998

 

(196,294

)

Total production revenue

 

$

1,417,538

 

$

2,372,829

 

(40

)%

$

(1,326,859

)

$

371,568

 

$

(955,291

)

Total oil volume — MBbls

 

18,663

 

15,639

 

19

%

 

 

 

 

 

 

Oil volume — barrels per day

 

51,132

 

42,846

 

19

%

 

 

 

 

 

 

Oil percentage of total production

 

31

%

30

%

 

 

 

 

 

 

 

 

Average oil price — per barrel

 

$

43.38

 

$

83.70

 

(48

)%

 

 

 

 

 

 

Total gas volume — MMcf

 

168,987

 

155,128

 

9

%

 

 

 

 

 

 

Gas volume — MMcf per day

 

463.0

 

425.0

 

9

%

 

 

 

 

 

 

Gas percentage of total production

 

47

%

49

%

 

 

 

 

 

 

 

 

Average gas price — per Mcf

 

$

2.53

 

$

4.43

 

(43

)%

 

 

 

 

 

 

Total NGL volume — MBbls

 

13,063

 

11,343

 

15

%

 

 

 

 

 

 

NGL volume — barrels per day

 

35,789

 

31,078

 

15

%

 

 

 

 

 

 

NGL percentage of total production

 

22

%

21

%

 

 

 

 

 

 

 

 

Average NGL price — per barrel

 

$

13.75

 

$

33.14

 

(59

)%

 

 

 

 

 

 

Total production — MMcfe

 

359,343

 

317,022

 

13

%

 

 

 

 

 

 

Total production — MMcfe per day

 

984.5

 

868.6

 

13

%

 

 

 

 

 

 

“As reflected in the table2018 Compared to 2017” section above our 2015 production revenue was 40% lower than thatfor general information regarding various statement of 2014.   Increased revenues from higheroperations line items.

Revenues
Realized prices and production volumes were more than offsethigher in 2017 as compared to 2016, which caused our revenues to increase by decreased revenues$652.8 million, or 53%, from lowerthe prior year. The following table shows our production revenue for the years indicated as well as the change in revenue due to changes in prices and volumes.
  Years Ended
December 31,		     Price / Volume Variance
Production Revenue (in thousands)
 2017 2016 Variance Between
2017 / 2016		 Price Volume Total
Oil sales $981,646
 $632,934
 $348,712
 55% $182,742
 $165,970
 $348,712
Gas sales 516,936
 388,786
 128,150
 33% 84,361
 43,789
 128,150
NGL sales 375,421
 199,498
 175,923
 88% 131,347
 44,576
 175,923
  $1,874,003
 $1,221,218
 $652,785
 53% $398,450
 $254,335
 $652,785
The table below presents our production volumes by commodity, our average realized commodity prices, and certain major U.S. index prices. The 13% year-over-year growth insale of our Permian Basin oil production volumesis typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. During 2017 and 2016, 78% and 80%, respectively, of our oil production was primarily due to our successful drilling programs in the Permian Basin andwith the majority of the remainder in the Mid-Continent region. See Production Volumes, Prices, and Costs and Exploration and Development Overview in Items 1 and 2Our realized prices do not include settlements of this report for further information and a discussion of 2015 activity in these regions.  See Revenues above, for information regarding realized prices.

Our 2015 aggregate production volumes were 359.3 Bcfe, comprised of 47% natural gas, 31% oil and 22% NGL. This compares to 2014 aggregate production volumes of 317.0 Bcfe, made up of 49% natural gas, 30% oil and 21% NGL.

49

commodity derivative contracts.

47

Table of Contents



  Years Ended
December 31,		 Variance Between
2017 / 2016
  2017 2016 
Oil        
Total volume — MBbls 20,861
 16,528
 4,333
 26%
Total volume — MBbls per day 57.2
 45.2
 12.0
 27%
Percentage of total production 30% 28%    
Average realized price — per barrel $47.06
 $38.30
 $8.76
 23%
Average WTI Midland price — per barrel $50.45
 $43.34
 $7.11
 16%
Average WTI Cushing price — per barrel $50.94
 $43.32
 $7.62
 18%
         
Gas        
Total volume — MMcf 187,468
 168,227
 19,241
 11%
Total volume — MMcf per day 513.6
 459.6
 54.0
 12%
Percentage of total production 45% 48%    
Average realized price — per Mcf $2.76
 $2.31
 $0.45
 19%
Average Henry Hub price — per Mcf $3.11
 $2.46
 $0.65
 26%
         
NGL        
Total volume — MBbls 17,374
 14,200
 3,174
 22%
Total volume — MBbls per day 47.6
 38.8
 8.8
 23%
Percentage of total production 25% 24%    
Average realized price — per barrel $21.61
 $14.05
 $7.56
 54%
         
Total        
Total production — MBOE 69,479
 58,765
 10,714
 18%
Total production — MBOE per day 190.4
 160.6
 29.8
 19%
Average realized price — per BOE $26.97
 $20.78
 $6.19
 30%
Other revenues

Revenues

We sometimes transport, process, and market some third-party gas that is associated with our equity gas. We market and sell gas for other working interest owners under short term agreements and may earn a fee for such services. The table below reflects income from third-party gas gathering and processing and our net marketing margin (revenues less purchases) for marketing third-party gas.  We market and sell natural gas for working interest owners under short term sales and supply agreements and may earn a fee for such services.

 

 

Years Ended December 31,

 

Gas Gathering and Marketing (in thousands):

 

2015

 

2014

 

Gas gathering and other revenues

 

$

34,688

 

$

49,602

 

Gas marketing revenues, net of related costs

 

$

393

 

$

1,745

 

  Years Ended December 31, 
Variance
Between
2017 / 2016
Gas Gathering and Marketing (in thousands):
 2017 2016 
Gas gathering and other $43,751
 $36,033
 $7,718
Gas marketing $495
 $94
 $401
Fluctuations in revenues from gas gathering and gas marketing activities are a function of increases and decreases in volumes, commodity prices, and prices associated with third party gas.  In 2015, revenuegathering rate charges. The increases from gas gathering declined by $14.9 million (30%),2016 are primarily due to lower realized prices which were partially offset by increased volumes.

an increase in prices.


48
Table of Contents


Operating Costs and Expenses

Total operating costs and expenses of $1.17 billion in 20152017 were $5.4636% lower than the $1.83 billion compared to $1.58 billion for the prior year.  As discussed aboveincurred in Operating costs and expenses, during 2015 our quarterly ceiling limitation calculations resulted in impairments totaling $4.0 billion.  Excluding the effect2016. Most of the impairments, our year-over-year operating costs and expenses decreased by $150.7 million.  Analyses of the year-over-year differences are discussed below.

 

 

 

 

 

 

Variance

 

 

 

 

 

 

 

Years Ended December 31,

 

Between

 

Per Mcfe

 

Operating Costs and Expenses

 

2015

 

2014

 

2015 / 2014

 

2015

 

2014

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

$

4,033,295

 

$

—

 

$

4,033,295

 

N/A

 

N/A

 

DD&A

 

731,460

 

775,577

 

(44,117

)

$

2.04

 

$

2.45

 

Asset retirement obligation

 

9,121

 

10,082

 

(961

)

$

0.03

 

$

0.03

 

Production

 

299,374

 

342,304

 

(42,930

)

$

0.83

 

$

1.08

 

Transportation, processing and other operating

 

182,362

 

195,414

 

(13,052

)

$

0.51

 

$

0.62

 

Gas gathering and other

 

38,138

 

35,113

 

3,025

 

$

0.11

 

$

0.11

 

Taxes other than income

 

84,764

 

128,793

 

(44,029

)

$

0.24

 

$

0.41

 

General and administrative

 

74,688

 

81,160

 

(6,472

)

$

0.21

 

$

0.26

 

Stock compensation

 

19,559

 

15,001

 

4,558

 

$

0.05

 

$

0.05

 

(Gain) loss on derivative instruments, net

 

(11,246

)

(3,762

)

(7,484

)

N/A

 

N/A

 

Other operating (income) expense, net

 

856

 

116

 

740

 

N/A

 

N/A

 

 

 

$

5,462,371

 

$

1,579,798

 

$

3,882,573

 

 

 

 

 

DD&A expense in 2015 decreased 6% compared to 2014.  Increased expense due to higher 2015 production volumes was more than offset by lower DD&A rates in 2015.  Thedecrease resulted from ceiling test impairments of our oil and gas properties discussed above, resultedof $757.7 million recorded in lower DD&A rates in each quarter following an impairment.  DD&A is calculated quarterly before the2016; we recorded no ceiling test impairment calculation.

Our year-over-year production costs decreased by 13% and accounted for 32%impairments in 2017. Also contributing to the decrease was the net gain on derivative instruments in 2017 compared to a net loss in 2016. Otherwise, all other categories of the aggregate decrease in operating costs and expenses excluding impairments.  increased in 2017. The following table shows our operating costs and expenses for the years indicated and a discussion of year-over-year differences follows.

  Years Ended December 31, Variance
Between
2017 / 2016		 Per BOE
Operating Costs and Expenses (in thousands, except per BOE)
 2017 2016  2017 2016
Impairment of oil and gas properties $—
 $757,670
 $(757,670) N/A
 N/A
Depreciation, depletion, and amortization 446,031
 392,348
 53,683
 $6.42
 $6.68
Asset retirement obligation 15,624
 7,828
 7,796
 $0.22
 $0.13
Production 262,180
 232,002
 30,178
 $3.77
 $3.95
Transportation, processing, and other operating 231,640
 190,725
 40,915
 $3.33
 $3.25
Gas gathering and other 35,840
 31,785
 4,055
 $0.52
 $0.54
Taxes other than income 89,864
 61,946
 27,918
 $1.29
 $1.05
General and administrative 79,996
 73,901
 6,095
 $1.15
 $1.26
Stock compensation 26,256
 24,523
 1,733
 $0.38
 $0.42
(Gain) loss on derivative instruments, net (21,210) 55,749
 (76,959) N/A
 N/A
Other operating expense, net 1,314
 755
 559
 N/A
 N/A
  $1,167,535
 $1,829,232
 $(661,697)  
  
Ceiling Test Impairment

We use the full cost method of accounting for our oil and gas operations.  Accounting rules require us to perform a quarterly ceiling test calculation to test our capitalized oil and gas property costs for possible impairment.  If the net capitalized cost of our oil and gas properties, as adjusted for income taxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum of: (i) the present value discounted at 10% of estimated future net revenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, as adjusted for income taxes.  Estimated future net revenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.

At each quarter-end date during the year ended December 31, 2017, the net capitalized cost of our oil and gas properties, as adjusted for income taxes, did not exceed the ceiling limitation, and, therefore, we did not recognize a ceiling test impairment during the year. The commodity prices used in the December 31, 2017 ceiling calculation, based on the required trailing twelve-month average prices, were $2.98 per Mcf of gas and $51.34 per barrel of oil.  A decline of approximately 19% or more in the value of the ceiling limitation would have resulted in an impairment at December 31, 2017.  During the year ended December 31, 2016, we recognized ceiling test impairments totaling $757.7 million ($481.4 million, net of tax).  These impairments were primarily the result of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the estimated future net revenues from proved reserves. Because the ceiling calculation uses trailing twelve-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation.  In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects.  Depending on fluctuations in these factors, including a decline in prices, we may incur full cost ceiling test impairments in future quarters. 

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

49
Table of Contents


Depreciation, Depletion, and Amortization
Depletion increased by $53.3 million, or 15%, during 2017 as compared to 2016. While prices increased in 2017 from 2016, thus increasing our reserves, so too did our exploration and development expenditures and activities, thus increasing our proved oil and gas properties and future development costs, causing an overall increase in depletion expense. DD&A consisted of the following for the years indicated:
  Years Ended December 31, Variance
Between
2017 / 2016		 Per BOE
DD&A Expense (in thousands, except per BOE)
 2017 2016  2017 2016
Depletion $399,328
 $346,003
 $53,325
 $5.75
 $5.89
Depreciation 46,703
 46,345
 358
 0.67
 0.79
  $446,031
 $392,348
 $53,683
 $6.42
 $6.68
Asset Retirement Obligation

Asset retirement obligation expense is typically primarily comprised of accretion expense. Asset retirement obligation expense includes $10.5 million in 2017 for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. See the “2018 Compared to 2017” section above for more information regarding this matter.

Production

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

 

 

 

 

 

 

Variance

 

 

 

 

 

 

 

Years Ended December 31,

 

Between

 

Per Mcfe

 

(in thousands)

 

2015

 

2014

 

2015 / 2014

 

2015

 

2014

 

Lease operating expense

 

$

249,744

 

$

276,395

 

$

(26,651

)

$

0.70

 

$

0.87

 

Workover expense

 

49,630

 

65,909

 

(16,279

)

0.13

 

0.21

 

 

 

$

299,374

 

$

342,304

 

$

(42,930

)

$

0.83

 

$

1.08

 

Lease

  Years Ended December 31, Variance
Between
2017 / 2016		 Per BOE
Production Expense (in thousands, except per BOE)
 2017 2016  2017 2016
Lease operating expense $215,148
 $189,291
 $25,857
 $3.10
 $3.22
Workover expense 47,032
 42,711
 4,321
 0.67
 0.73
  $262,180
 $232,002
 $30,178
 $3.77
 $3.95
Due to increased daily production in 2017, we reduced our per unit lease operating expense by 4% from 2016.  On an absolute basis, lease operating expense in 2015 declined 10%2017 increased 14%, or $25.9 million, compared to 2014.2016. The declineincrease was primarily acaused by: (i) increased saltwater disposal costs primarily attributed to the addition of new wells and recompleted wells, (ii) increased labor costs primarily due to additional employees and salary and bonus increases, (iii) increased equipment maintenance costs, primarily the result of property divestitures, lower salt water disposalthe addition of new wells, (iv) increased gas lift and fuel compression costs, and decreased equipment(v) increased chemicals and maintenancetreating costs.  These decreases were
Workover expense increased by 10%, or $4.3 million, during 2017 as compared to 2016. During 2017, we had costlier major well workover projects than during 2016, which increased expense. This increase was partially offset by increased expensethe receipt of partial insurance proceeds during 2017 related to new wells acquired and drilled.  Increased production volumesa flooding event in 2015 also contributed toand the lower rate per Mcfesubsequent remediation and repairs, the bulk of which took place in 2015.

Workover expense decreased by 25% in 2015 compared to 2014.2016. Generally, theseworkover costs will fluctuate based on the amount of maintenance and remedial activity planned and/or required during the period.

Our 2015 year-over-year transportation,

Transportation, Processing, and Other Operating
Transportation, processing, and other operating costs in 2017 were 7% lower21%, or $40.9 million, higher than those in 2014. These costs will vary by2016.  This increase was primarily due to increased production volumes and, to a lesser extent, increased transportation and processing rates in 2017 as compared to 2016.
Gas Gathering and Other
Gas gathering and other in 2017 was 13%, or $4.1 million, higher than in 2016.  This increase was primarily due to higher product type and region.  In 2015, lower prices for natural gas and NGLs resulted in lower costs associated with fuelprocessing third-party production due to higher commodity prices. These increased product costs were offset by increases in associated revenue.

50
Table of Contents


Taxes Other than Income
In 2017, taxes other than income increased 45%, or $27.9 million, from 2016.  This increase was primarily due to the increase in revenue seen between the comparable periods.  Taxes other than income were 4.8% and processing fees, which5.1% of production revenues for 2017 and 2016, respectively. The percentage decreased from 2016 due to the approval of reduced tax rates on several of our high-cost gas wells in Texas and, as part of that process, approved severance tax refunds of $9.1 million.
General and Administrative
G&A costs consisted of the following:
  Years Ended December 31, Variance
Between
2017 / 2016
General and Administrative Expense (in thousands):
 2017 2016 
Gross G&A $156,389
 $146,432
 $9,957
Less amounts capitalized to oil and gas properties (76,393) (72,531) (3,862)
G&A expense $79,996
 $73,901
 $6,095
The percentage of gross G&A capitalized was 49% and 50% during 2017 and 2016, respectively. G&A expense during 2017 was 8%, or $6.1 million, higher than during 2016.  This increase is primarily due to the following increases: (i) other employee compensation, primarily due to increased incentive bonus expense, (ii) insurance, (iii) consulting, (iv) salaries and wages, due to additional employees and salary increases, and (v) charitable donations. These increases were partially offset by higher processing volumes.  Approximately 5% of the 2015 costs relates to accruals for expected minimum volume agreement shortfallsdecreased severance expense due to reduced drilling activity in 2015 and projected at the time fora voluntary early retirement incentive program, which included severance pay, that was offered to certain employees during 2016.

Gas gathering and other includes costs associated with operating our gas gathering and processing infrastructure, including product costs, operating and maintenance expenses.  The year-over-year increase is due primarily to higher overall costs related to increased activity, which were largely offset by lower costs associated with product purchases.

Taxes other than income are assessed by state and local taxing authorities on production, revenues or the value of properties. Revenue based production and severance taxes comprised approximately 81% and 85% of these taxes for 2015 and 2014, respectively. The 34% decrease in 2015 taxes resulted primarily from lower production revenues due to lower realized commodity prices and accounted for 33% of the aggregate decrease in operating costs and expenses, excluding impairments.

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

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2015

 

2014

 

2015 / 2014

 

G&A capitalized to oil and gas properties

 

$

58,332

 

$

76,636

 

$

(18,304

)

G&A expense

 

74,688

 

81,160

 

(6,472

)

 

 

$

133,020

 

$

157,796

 

$

(24,776

)

During 2015, aggregate G&A declined 16% compared to 2014.  Because of the adverse effect of lower commodity prices on our financial results, we reduced our expectations and accruals for short-term incentive-based cash compensation and benefits.

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

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2015

 

2014

 

2015 / 2014

 

Restricted stock awards

 

 

 

 

 

 

 

Performance stock awards

 

$

18,991

 

$

12,141

 

$

6,850

 

Service-based stock awards

 

14,547

 

13,607

 

940

 

 

 

33,538

 

25,748

 

7,790

 

Stock option awards

 

2,803

 

3,057

 

(254

)

 

 

36,341

 

28,805

 

7,536

 

Less amounts capitalized

 

(16,782

)

(13,804

)

(2,978

)

Stock compensation

 

$

19,559

 

$

15,001

 

$

4,558

 

Expense associated with

  Years Ended December 31, Variance
Between
2017 / 2016
Stock Compensation Expense (in thousands):
 2017 2016 
Restricted stock awards:  
  
  
Performance stock awards $26,020
 $24,183
 $1,837
Service-based stock awards 19,746
 18,391
 1,355
  45,766
 42,574
 3,192
Stock option awards 2,599
 2,565
 34
Total stock compensation cost 48,365
 45,139
 3,226
Less amounts capitalized to oil and gas properties (22,109) (20,616) (1,493)
Stock compensation expense $26,256
 $24,523
 $1,733
Periodic stock compensation expense will fluctuate based on the grant-dategrant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The increase in 2015total stock compensation cost in 2017 as compared to 2016 is primarily relateddue to performance awards granted in December 2014, a portioneither during or subsequent to 2016. These increases were partially offset by awards vesting prior to or during 2017.


51
Table of which were amortized during 2015.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.  See Note 6 to the Consolidated Financial Statements in Item 8 of this report for further discussion regarding our stock-based compensation.

Net gains and lossesContents



(Gain) Loss on our derivative instruments are a function of fluctuations in the underlying commodity prices and the monthly settlement (if any) of the instruments. We have chosen not to apply hedge accounting treatment to our derivative instruments.  As a result, settlements on the contracts are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments.

Derivative Instruments, Net


The following table presents the aggregate net (gain)components of (Gain) loss from settlements and changes in the fair value of our derivative contracts and the (gains) losses from cash settlements included in the aggregate gain (loss) on derivative instruments, net.net for the periods indicated.  See Note 4 to the Consolidated Financial Statements in Item 8 of this report for further detailsadditional information regarding our derivative instruments.

 

 

Years Ended December 31,

 

(in thousands)

 

2015

 

2014

 

(Gain) loss on derivative instruments, net

 

$

(11,246

)

$

(3,762

)

Settlement (gains) losses

 

$

—

 

$

(7,641

)

  Years Ended December 31, Variance
Between
2017 / 2016
(Gain) Loss on Derivative Instruments, Net (in thousands):
 2017 2016 
Decrease (increase) in fair value of derivative instruments, net:  
  
  
Gas contracts $(40,226) $27,462
 $(67,688)
Oil contracts 17,383
 35,724
 (18,341)
  (22,843) 63,186
 (86,029)
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (4,557) (6,467) 1,910
Oil contracts 6,190
 (970) 7,160
  1,633
 (7,437) 9,070
(Gain) loss on derivative instruments, net $(21,210) $55,749
 $(76,959)
Other (income)Income and expense

 

 

 

 

 

 

Variance

 

 

 

Years Ended December 31,

 

Between

 

(in thousands)

 

2015

 

2014

 

2015 / 2014

 

Interest expense

 

$

85,746

 

$

72,865

 

$

12,881

 

Capitalized interest

 

(30,589

)

(35,925

)

5,336

 

Other, net

 

(13,576

)

(28,907

)

15,331

 

 

 

$

41,581

 

$

8,033

 

$

33,548

 

Expense

  Years Ended December 31, Variance
Between
2017 / 2016
Other Income and Expense (in thousands):
 2017 2016 
Interest expense $74,821
 $83,272
 $(8,451)
Capitalized interest (22,948) (21,248) (1,700)
Loss on early extinguishment of debt 28,187
 —
 28,187
Other, net (11,342) (10,707) (635)
  $68,718
 $51,317
 $17,401
The majority of ourdecrease in interest expense relatesin 2017 as compared to interest on debt2016 was due to the completion of a tender offer and amortizationredemption of financing costs. The 18% year-over-year increase is primarily due to$750 million 5.875% senior notes and the issuance of $750 million of3.90% senior notes, which occurred during the second quarter of 2017. The $28.2 million loss on early extinguishment of debt incurred during 2017 was also associated with the debt tender offer and redemption. The loss was composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.

There were higher capitalized costs subject to interest capitalization in June2017 as compared to 2016 due to our increased capitalized expenditures. However, the impact of 2014.  See Long-Term Debt below for further information regardingthe increase in capitalized interest was largely offset by the lower interest rate on borrowings outstanding due to the replacement of our debt.

We capitalize5.875% notes with 3.90% notes in the second quarter of 2017.


Other, net includes interest onincome of $5.4 million and $3.7 million in 2017 and 2016, respectively. Interest rates were raised once at the capitalized costend of unproved properties, the in-progress costs of drilling2016 and completing wells and constructing qualified assets.  Capitalizedthree times in 2017, increasing our interest will fluctuate basedincome earned on our current rateshort-term investments. Other components of interest and the amount of costs on which interest is calculated.

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



52
Table of the 53% year-over-year decrease in income was due to lower net gains on transactions related to oil and gas well equipment and supplies and lower gains from sales of fixed assets.

Contents



Income tax expense

Tax Expense (Benefit)

The components of our provisionIncome Tax Expense (Benefit) were as follows:
  Years Ended December 31, Variance
Between
2017 / 2016
Income Tax Expense (Benefit) (in thousands):
 2017 2016 
Current tax benefit $(2,812) $(1,115) $(1,697)
Deferred tax expense (benefit) 190,479
 (213,286) 403,765
  $187,667
 $(214,401) $402,068
       
Combined federal and state effective income tax rate 27.5% 34.4%  

On December 22, 2017, the United States enacted H.R.1 (Public Law 115-97), commonly referred to as the Tax Cuts and Jobs Act or U.S. Tax Reform. We remeasured the deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2017 and, as a result of this remeasurement, we recorded an income taxes aretax benefit of $61.1 million and a corresponding $61.1 million decrease in the net deferred tax liabilities as follows:

 

 

Years Ended December 31,

 

(in thousands)

 

2015

 

2014

 

Current tax expense (benefit)

 

$

14,710

 

$

404

 

Deferred tax expense

 

(1,486,439

)

309,443

 

 

 

$

(1,471,729

)

$

309,847

 

Combined federal and state effective income tax rate

 

36.3

%

37.1

%

of December 31, 2017. See the “2018 Compared to 2017” section above for more information regarding this matter.


Our combined federal and state effective tax rates, differas shown above, differed from the statutory rate at the time of 35% primarily due to state income taxes, non-deductible expenses, revisions, and revisions.the impact of changes in tax law. See Note 9 to the Consolidated Financial Statements in Item 8 of this report for further information regarding our income taxes.



LIQUIDITY AND CAPITAL RESOURCES

Overview

We strive to maintain an adequate liquidity level to address volatility and risk.  Sources of liquidity include our cash flow from operations, cash on hand, available borrowing capacity under our revolving credit facility, proceeds from sales of non-core assets, including our Ward County asset sale that closed in August 2018, and, occasionalfrom time to time, public financings based on our monitoring of capital markets and our balance sheet.

Our liquidity is highly dependent on prices we receive for the oil, natural gas, and NGLs we produce.  Prices we receive are determined by prevailing market conditions and greatly influence our revenue, cash flow, profitability, access to capital, and future rate of growth.  See Market Conditions, Revenues and RESULTS OF OPERATIONS Revenuesabove for further information and analysis ofregarding the impact realized prices have had on our 20162018 earnings.


In connection with the expected closing of our acquisition of Resolute, we anticipate utilizing cash on hand to fund the cash portion of the merger consideration, acquisition fees and expenses, and the repayment of the outstanding balance on Resolute’s revolving credit facility, all of which we estimate will be between $600 million and $630 million. In addition, we intend to redeem and repay the $600 million senior notes of Resolute. This transaction is expected to close in the first quarter of 2019.

We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program.  We have a balanced and abundant drilling inventory and limited long-term commitments, which enables us to respond quickly to industry volatility.  Based on current economic conditions, and assuming the successful acquisition of Resolute, our 20172019 exploration and development (“E&D”) expenditures are projected to range from $1.1 — $1.2$1.35 billion to $1.45 billion.  Investments in gathering, and processing, infrastructure and other fixed assetsinfrastructure are expected to approximatebe an additional $60 million.million to $70 million for 2019.  See Capital Expenditures below for information regarding our 2016 exploration and development (E&D)2018 E&D activities.


We periodically use derivative instruments to mitigate volatility in commodity prices.  At December 31, 2016,2018, we had derivative contracts covering a portion of our 20172019 and 20182020 production.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may hedge up to 50% ofincrease or decrease our oil and natural gas production on a forward five-quarter basis.derivative positions from current levels.  See Note 4 to the Consolidated Financial Statements in Item 8 of this report for information regarding our derivative instruments.


53
Table of Contents


We believe our conservative use of leverage, strong balance sheet, and hedging activities will mitigate our exposure to lower prices.  Cash and cash equivalents at December 31, 20162018 were $652.9$800.7 million.  OurAt December 31, 2018, our long-term debt consisted of $1.5$1.50 billion of senior unsecured notes, with $750 million 4.375% notes due in 20222024 and $750 million 3.90% notes due in 2024.  We2027.  At December 31, 2018, we had no borrowings and $2.5 million in letters of credit outstanding under our credit facility, of $2.5 million, leaving an unused borrowing availability of $997.5 million.

  See Long-Term Debt below for more information regarding our debt. 

Our debt to total capitalization ratio at December 31, 20162018 was 42%.  The reconciliation31%, down from 37% at December 31, 2017.  This ratio is calculated by dividing the principal amount of debt to total capitalization, which is a non-GAAP measure, is: long-term debt of $1.5 billion divided by the sum of (i) the principal amount of long-term debt of $1.5 billion plusand (ii) total stockholders’ equity, of $2.04 billion.with all numbers coming directly from the Consolidated Balance Sheet.  Management uses this non-GAAP measureratio as one indicator of our financial condition.  Managementcondition and believes professional research analysts and rating agencies use this non-GAAP measureratio for this purpose and to compare our financial condition to other companies’ financial conditions.

We expect our operating cash flow and other capital resources to be adequate to meet our needs for planned capital expenditures, working capital, debt service, and dividends declared in 2017 and beyond.

Sources and Uses of Cash

Our primary sources of liquidity and capital resources are operating cash flow, borrowings under our credit facility, asset sales and occasional public financings based on our monitoring of capital markets and our balance sheet. Our primary uses of funds are expenditures for exploration and development, leasehold and property acquisitions, other capital expenditures, debt service, and cash dividends paid to holders of our common stock.

The decline in year-over-year realized prices for our oil and natural gas production adversely impacted our operating cash flow for 2016 and consequently reduced the amount of cash flow available for exploration and development activities.  See Market Conditions above for further information regarding prevailing economic conditions.

The following table presents our sources and uses of cash and cash equivalents from 2014 to 2016.  Capital expenditures are presented on a cash basis.  These amounts differ from capital expenditures (including accruals) that are referred to elsewhere in this report.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Sources of cash and cash equivalents:

 

 

 

 

 

 

 

Operating cash flow

 

$

599,225

 

$

691,500

 

$

1,619,365

 

Sales of oil and gas and other assets

 

29,376

 

41,031

 

458,394

 

Increase in other long-term debt

 

—

 

—

 

750,000

 

Proceeds from sale of common stock

 

—

 

752,100

 

—

 

Proceeds from exercise of stock options and other

 

4,804

 

21,439

 

11,898

 

Total sources of cash and cash equivalents

 

633,405

 

1,506,070

 

2,839,657

 

Uses of cash and cash equivalents:

 

 

 

 

 

 

 

Oil and gas capital expenditures

 

(699,558

)

(979,044

)

(2,108,250

)

Other capital expenditures

 

(22,228

)

(70,592

)

(90,611

)

Net decrease in bank debt

 

—

 

—

 

(174,000

)

Financing and underwriting fees

 

(101

)

(24,633

)

(11,616

)

Dividends paid

 

(38,024

)

(58,281

)

(53,849

)

Total uses of cash and cash equivalents

 

(759,911

)

(1,132,550

)

(2,438,326

)

Net increase (decrease) in cash and cash equivalents

 

$

(126,506

)

$

373,520

 

$

401,331

 

Cash and cash equivalents at end of year

 

$

652,876

 

$

779,382

 

$

405,862

 

next twelve months.

Analysis of Cash Flow Changes (See
The following table presents the totals of the major cash flow classification categories from our Consolidated Statements of Cash Flows in Item 8 of this Report)

for the periods indicated. 

  Years Ended December 31,
(in thousands) 2018 2017 2016
Net cash provided by operating activities $1,550,994
 $1,096,564
 $625,849
Net cash used by investing activities $(1,085,618) $(1,265,897) $(692,410)
Net cash used by financing activities $(65,244) $(83,009) $(59,945)
Net cash flow provided by operating activities (operating cash flow) for 2016in 2018 was $599.2$1.55 billion, up $454.4 million, down 13%or 41%, from $691.5 million for 2015.$1.10 billion in 2017. The $92.3 million decreaseincrease was primarily a result of higher revenues due to higher production volumes and realized oil and NGL prices in 2018. Also contributing to the increase was a decreased investment in working capital, primarily caused by the timing of cash receipts of accounts receivable. These increases were partially offset by increased net decreaseoperating expenses, primarily production expense and taxes other than income, and increased cash outflows for settlements of derivative instruments. Net cash provided by operating activities in production2017 was $1.10 billion, up $470.7 million, or 75%, from $625.8 million in 2016. The increase was primarily a result of higher revenue from lowerdue to higher realized commodity prices and production volumes in 2016.  The 2016 decrease in production revenue2017. This increase was partially offset by lower netincreased operating expenses and an increased proceeds from settlements of our derivative instruments.  In 2015, operating cash flow was 57% lower than 2014, resulting from a net decreaseinvestment in production revenue due to lower realized commodity prices in 2015, which was partially offset by lower net operating costs in 2015.working capital. See RESULTS OF OPERATIONS above for detailsmore information regarding year-over-year changes in production revenuesrevenue and operating expenses.

In 2016,2018, net cash flow used forby investing activities was $1.09 billion, compared to $1.27 billion and $692.4 million compared to $1.0 billionin 2017 and 2016, respectively. The majority of our cash flows used by investing activities are for 2015 and $1.7 billion for 2014. WeaknessE&D capital expenditures, which, as reflected in commodity prices has had a significant adverse impact on the amountstatements of cash flow available to investflows, were $1.57 billion, $1.23 billion, and $699.6 million in exploration2018, 2017, and development (E&D) activities.  In 2016, our E&D andrespectively. Our other capital expenditures, which are primarily for our midstream assets, were $721.8$103.5 million, $45.4 million, and $22.2 million in 2018, 2017, and 2016, respectively. In 2018, cash outflows for capital expenditures were partially offset by proceeds from asset sales of $29.4 million. Our 2015 E&D and other capital expenditures were $1.0 billion,$584.4 million, which were partially offset byincludes $534.6 million in net cash proceeds from the August 2018 divestiture of oil and gas properties principally located in Ward County, Texas for which the final cash settlement, which will reflect customary post-closing adjustments, is scheduled to occur by the end of first quarter 2019. Net cash proceeds from other asset sales of $41.0 million. For 2014, our E&Dtotaled $49.9 million, $12.6 million, and other capital expenditures were $2.2 billion, which were partially offset by proceeds from$29.4 million in 2018, 2017, and 2016, respectively. These asset sales are primarily for the divestiture of $458.4 million.

non-core oil and gas properties.

Net cash flow used by financing activities was $65.2 million, $83.0 million, and $59.9 million in 2018, 2017, and 2016, was $33.3 million compared torespectively. All years include the payment of dividends, the payment of income tax withholdings made on behalf of our employees upon the net cash flow provided by financing activities in 2015settlement of $690.6 million.  In 2016, proceeds of $4.8 million from issuance of commonemployee stock from employee option exercisesawards, and other were more than offset by dividend payments and financing fees of $38.1 million.

In 2015, net cash flow provided by financing activities of $690.6 million included approximately $730 million of net proceeds from the sale of common stock and $21.4 millionreceipt of proceeds from issuancestock option exercises. Dividends paid were $55.2 million, $30.5 million, and $38.0 million in 2018, 2017, and 2016, respectively. During the years presented, we have declared cash dividends quarterly, paying them in the following quarter. We paid dividends totaling $0.58 per share, $0.32 per share, and $0.40 per share in 2018, 2017, and 2016, respectively. We paid employee income tax withholdings on the net settlement of common stock awards totaling $12.1 million,


54
Table of Contents


$21.7 million, and $26.6 million in 2018, 2017, and 2016, respectively. Cash proceeds received from employeestock option exercises and other.  These cash flows were partially offset by dividend payments of $58.3$2.2 million, $0.4 million, and $2.5$4.8 million, in 2018, 2017, and 2016, respectively. Additionally, 2017 included: (i) the early extinguishment of $750 million 5.875% senior notes, which included $22.6 million of financing costs.

Net cash flow provided by financing activities of $522.4 million in 2014 includedtender and redemption premiums and (ii) the issuance of $750 million of3.90% senior notes and $11.9at 99.748% of par for proceeds of $748.1 million, of proceeds from the issuance of common stock from employee option exercisespaying $6.3 million in underwriting, financing, and other which were partially offset by payments of $174.0 million on our credit facility, $11.6 million for financing and underwriting fees and dividend payments of $53.8 million.

Adjusted Cash Flow from Operations

The following table provides a reconciliation from the GAAP measure of net cash provided by operating activities to the non-GAAP measure adjusted cash flow from operations:

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Net cash provided by operating activities

 

$

599,225

 

$

691,500

 

$

1,619,365

 

Change in operating assets and liabilities

 

29,913

 

52,082

 

14,847

 

Adjusted cash flow from operations

 

$

629,138

 

$

743,582

 

$

1,634,212

 

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

costs.  

Capital Expenditures

The following table reflects capitalized expenditures for oil and gas acquisitions, exploration, and development activities, andnet of property sales:

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

Acquisitions:

 

 

 

 

 

Proved

 

$

2,678

 

$

30

 

Unproved

 

11,865

 

6,666

 

Net purchase price adjustments (*)

 

—

 

(11,653

)

 

 

14,543

 

(4,957

)

Exploration and development:

 

 

 

 

 

Land and seismic

 

61,870

 

52,049

 

Exploration

 

40

 

1,073

 

Development

 

672,842

 

823,830

 

 

 

734,752

 

876,952

 

Property sales

 

(24,687

)

(41,276

)

 

 

$

724,608

 

$

830,719

 

(*)  The net 2015 purchase price adjustments relate to activity in prior periods.

Capital expenditures

  Years Ended December 31,
(in thousands) 2018 2017 2016
Acquisitions:  
  
  
Proved $62
 $938
 $2,678
Unproved 26,216
 6,853
 11,865
  26,278
 7,791
 14,543
Exploration and development:  
  
  
Land and seismic 82,791
 140,516
 61,870
Exploration and development 1,487,453
 1,140,548
 672,882
  1,570,244
 1,281,064
 734,752
Property sales (581,799) (11,680) (24,687)
  $1,014,723
 $1,277,175
 $724,608
Amounts in the table above are presented on an accrual basis. Oil and gas capital expenditures and sales of oil and gas assets in the Consolidated Statements of Cash Flows in this report reflect capital expenditures on a cash basis, when payments are made and proceeds received.

Because of lower commodity prices, we reduced

We increased our 20162018 E&D expenditures 16%23% to $734.8 million$1.57 billion compared to $877.0 million$1.28 billion in 2015.2017. Approximately 59%70% of our 20162018 E&D expenditures were in the Permian Basin and 40%30% were in our Mid-Continent region.the Mid-Continent. During 2016,2018, we completed or participated in the drilling and completion of 154349 gross (61(122.1 net) wells, 73 of which we operated.operated 146 gross (105.8 net) wells. See Items 1 and 2 of this report for further information regarding our wells drilled and other information regarding our oil and gas properties.

Approximately 66%85% of our planned 20172019 E&D capital investment of $1.1 — $1.2$1.35 billion to $1.45 billion is expected to be invested in the Permian Basin and most of the remainder in the Mid-Continent region.

Mid-Continent.

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

We intend to fund our 20172019 capital program and the acquisition of Resolute with cash flow from our operating activities, and cash on hand, at December 31, 2016.and borrowings under our credit facility. Sales of non-core assets and borrowings under our Credit Facilitypossible capital markets transactions may also be used to supplement funding of capital expenditures.expenditures and acquisitions. The timing of capital expenditures and the receipt of cash flows do not necessarily match, which may cause us to borrow and repay funds under our Credit Facilitycredit facility from time-to-time. See Long-Term Debt—Bank Debt below for further information regarding our credit facility.


On November 18, 2018, we entered into an agreement and plan of merger to acquire Resolute in a cash and stock transaction valued at a total purchase price of approximately $1.6 billion, including the assumption of Resolute’s long-term debt, which was $710 million as of September 30, 2018. Under the terms of the agreement, Resolute shareholders will have the right to receive 0.3943 shares of Cimarex common stock, $35.00 per share in cash, or a combination of $14.00 per share in cash and 0.2366 shares of Cimarex common stock. The amount of stock and cash is subject to proration for a total stock and cash mix of 60% and 40%, respectively. Assuming completion of the acquisition, Resolute’s former stockholders will own approximately 6.4% of our outstanding common stock based on shares outstanding for both companies as of January 18, 2019. The cash portion of the merger consideration, acquisition fees and expenses, and the repayment of the outstanding balance on Resolute’s revolving credit facility, all of which

55
Table of Contents


are estimated to be between $600 million and $630 million, are expected to be funded through cash on hand. In addition, we intend to redeem and repay the ordinary course$600 million senior notes of business we actively evaluate opportunitiesResolute. This acquisition will expand Cimarex’s footprint in Reeves County, Texas by 21,100 net acres that are complementary to purchase properties that we believe could benefit from our technical capabilities, particularly in our core areasexisting Reeves County position. The transaction, which is expected to be completed by the end of operations. We also evaluate our non-core property holdings for potential divestitures. For further information on our property acquisitions and dispositions, see Note 12the first quarter 2019, is subject to the Consolidated Financial Statements in Item 8approval of this report.

Resolute shareholders and the satisfaction of certain regulatory approvals and other customary closing conditions.


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

  See Item 1A Financial ConditionRISK FACTORS

During 2016, our total assets decreased $470.7 million (10%) to $4.2 billion.  Most for a description of the decreaserisks related to net oilcurrent and gas properties, which declined by $387.0 million.  In 2016, $757.7 million of impairmentspotential future environmental and DD&A of $392.3 million were only partially offset by net additions to oilsafety regulations and gas properties of $716.7 million.  The remaining decrease in total assets was primarily related to a decrease of $126.5 million in cashrequirements that could adversely affect our operations and cash equivalents.

Total liabilities at year-end 2016 were $2.19 billion, down $55.3 million (2%) from $2.25 billion at year-end 2015. During 2016, deferred income taxes declined $213.0 million primarily as a result of our net loss for the year.  The decline in deferred income taxes was partially offset by a net increase in current liabilities of $112.3 million.

At December 31, 2016, stockholders’ equity totaled $2.04 billion, a decrease of $415.4 million (17%) from $2.46 billionfinancial condition.

Long-Term Debt
Long-term debt at December 31, 2015.  The decrease resulted primarily from our 2016 net loss of $408.8 million.

The 2016 decreases in our total assets, liabilities2018 and stockholders’ equity and our net loss for the year resulted primarily from the $757.7 million aggregate impairments of our oil and gas properties.  During the first three quarters of 2016, impairments resulted from the continued impact of lower prices on the present value of future cash flows from our proved reserves used in our full cost ceiling limitation calculation.  As noted above under Operating costs and expenses, the ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

Long-Term Debt

Long-term debt at year-end 2016 and 20152017 consisted of the following:

 

 

December 31, 2016

 

December 31, 2015

 

 

 

 

 

Unamortized Debt

 

Long-term

 

 

 

Unamortized Debt

 

Long-term

 

(in thousands)

 

Principal

 

Issuance Costs

 

Debt, net

 

Principal

 

Issuance Costs

 

Debt, net

 

5.875% Senior Notes

 

$

750,000

 

$

(5,691

)

$

744,309

 

$

750,000

 

$

(6,978

)

$

743,022

 

4.375% Senior Notes

 

750,000

 

(6,370

)

743,630

 

750,000

 

(7,402

)

742,598

 

Total long-term debt

 

$

1,500,000

 

$

(12,061

)

$

1,487,939

 

$

1,500,000

 

$

(14,380

)

$

1,485,620

 

At each of December 31, 2016 and 2015 we had no bank debt outstanding.  All of our long-term debt is senior unsecured debt and is, therefore, pari passu with other unsecured debt with respect to the payment of both principal and interest.

  December 31, 2018 December 31, 2017
(in thousands)

 Principal 
Unamortized  Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized  Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes $750,000
 $(4,439) $745,561
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,007) 742,993
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(11,446) $1,488,554
 $1,500,000
 $(13,080) $1,486,920
 ________________________________________
(1)At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.4 million and $1.6 million, respectively.  At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively. The 4.375% notes were issued at par.
Bank Debt

In October 2015, we entered into a new senior unsecured revolving credit facility (Credit Facility)(“Credit Facility”) with an initial aggregate commitment from the lenders of $1.0 billion.  We have the option to increase the commitment to $1.25 billion, at any time. Unlike the prior credit facility, the new Credit Facilitywhich matures October 16, 2020. There is not ano borrowing base facility subject to the discretion of the lenders and is not based on the value of our proved reserves.

Atreserves under the Credit Facility. As of December 31, 2016,2018, we had no bank borrowings outstanding under the Credit Facility, but did have letters of credit outstanding of $2.5 million under the Credit Facility,outstanding, leaving an unused borrowing availability of $997.5 million. We did not have any bank

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.125 - 2.0% based on the credit rating for our senior unsecured long-term debt, outstanding during 2016. In 2015, we had average daily bank debt outstandingor (b) a base rate (as defined in the credit agreement) plus 0.125 - 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of $27.4 thousand and0.125 - 0.35%, based on the highest amount of bank borrowings outstanding during 2015 was $10.0 million in May.

credit rating for our senior unsecured long-term debt.

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. For further information regardingAs of December 31, 2018, we were in compliance with all of the termsfinancial and non-financial covenants.
At December 31, 2018 and 2017, we had $2.2 million and $3.4 million, respectively, of unamortized debt issuance costs associated with our Credit Facility that were recorded as deferred assets and included in “Other assets” in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit Facility see Note 3Facility.

56
Table of Contents


On February 5, 2019, we entered into an Amended and Restated Credit Agreement. Among other things, the amended and restated credit facility increases the aggregate commitment to $1.25 billion with an option to increase the Consolidated Financial Statements in Item 8 of this report.

commitment to $1.5 billion, and extends the maturity date to February 5, 2024.


Senior Notes

Our

On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% senior unsecured notes arefor cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered.  We settled these tendered notes for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest.  We recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.
On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 1, 202215, 2027 at 99.748% of par to yield 3.93% per annum.  We received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and ourdebt issuance costs.  The notes bear an annual interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment occurring November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. 
In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024.  Interest2024 and interest is payable semiannually on June 1 and December 1.  
Each of our senior notes is payable semi-annually.  Each of the seniorunsecured notes is governed by an indenture containing customarycertain covenants, events of default, and other restrictive provisions.  For further information regarding our seniorprovisions with which we were in compliance as of December 31, 2018. The effective interest rate on the 4.375% notes see Note 3 toand the Consolidated Financial Statements in Item 83.90% notes, including the amortization of this report.

debt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively.

Working Capital Analysis

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

At December 31, 2016,2018, we had working capital of $447.0$715.4 million, a decreasean increase of $220.9$459.4 million, (33%)or 179%, compared to working capital of $667.9$256.1 million at December 31, 2015.

2017.

Working capital increases consisted primarily of the following:

Cash and cash equivalents increased $400.1 million. This is primarily due to the receipt of $534.6 million in net cash proceeds from the August 2018 divestiture of oil and gas properties principally located in Ward County, Texas.
Our net current derivative instruments increased in value by $101.2 million from a net current liability at December 31, 2017 to a net current asset at December 31, 2018.

Working capital decreases consisted primarily of the following:


·•                  Cash and cash equivalents decreased by $126.5 million.

·                  Net derivative instrument liability increased $60.1 million.

·Operations-related accounts payable and accrued liabilities increased $37.3$33.6 million.

·

Accrued liabilities related to our E&D expenditures increased by $25.6$8.9 million.

·                  Oil and gas well equipment and supplies decreased by $21.2 million.

Decreases in working capital were partially offset by the following:

·                  Operations-related accounts receivable increased $49.2 million

Accounts receivable are a major component



57
Table of 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 has historically been timely and losses associated with uncollectible receivables have not been significant.

Contents



Dividends

A quarterly cash dividend has been paid to stockholders every quarter since the first quarter of 2006. In February 2016, the quarterly dividend declared was decreased from $0.16 per share to $0.08 per share, fromwhere it remained through the fourth quarter of 2017. In the first and second quarters of 2018, we declared dividends of $0.16 per share and in the third and fourth quarters of 2018, we declared dividends of $0.18 per share. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by our Board of Directors.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Dividends declared from Retained earnings (in millions)

 

$

7.5

 

$

59.3

 

$

55.7

 

Dividends declared from Paid-in capital (in millions)

 

$

22.8

 

$

—

 

$

—

 

Dividends per share

 

$

0.32

 

$

0.64

 

$

0.64

 

See Note 2 to the Consolidated Financial Statements in Item 8 of this report for further information regarding dividends.

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 December 31, 2016,2018, our material off-balance sheet arrangements includedconsisted of operating lease agreements, which are customaryincluded in the oil and gas industry.

table below.

Contractual Obligations and Material Commitments

At December 31, 2016,2018, we had the following contractual obligations and material commitments.

 

 

Payments Due by Period

 

 

 

 

 

1 Year or

 

 

 

 

 

More than

 

Contractual obligations:

 

Total

 

Less

 

2 - 3 Years

 

4 - 5 Years

 

5 Years

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

Long-term debt (1)

 

$

1,500,000

 

$

—

 

$

—

 

$

—

 

$

1,500,000

 

Fixed-rate interest payments (1)

 

478,542

 

76,876

 

153,750

 

153,750

 

94,166

 

Operating leases

 

96,923

 

9,585

 

21,208

 

21,949

 

44,181

 

Drilling commitments (2)

 

157,505

 

157,505

 

—

 

—

 

—

 

Asset retirement obligation (3)

 

154,523

 

13,753

 

—

 

—

 

—

 

Other liabilities (4)

 

177,455

 

88,793

 

54,905

 

6,956

 

26,801

 

Firm transportation

 

26,383

 

7,655

 

6,549

 

4,427

 

7,752

 

commitments:

(1)         See Item 7A: Interest Rate Risk for more information regarding fixed and variable rate debt.

(2)

  Payments Due by Period
Contractual obligations (in thousands):
 Total 1/1/19 - 12/31/19 1/1/20 - 12/31/21 1/1/22 - 12/31/23 1/1/24 and Thereafter 
Long-term debt-principal (1) $1,500,000
 $—
 $—
 $—
 $1,500,000
 
Long-term debt-interest (1) 429,094
 60,844
 124,125
 124,125
 120,000
 
Operating leases (2) 109,832
 23,007
 43,431
 22,563
 20,831
 
Unconditional purchase obligations (3) 64,593
 24,263
 27,967
 6,900
 5,463
 
Derivative liabilities 29,894
 27,627
 2,267
 —
 —
 
Asset retirement obligation (4) 166,904
 14,146
 —
(4)—
(4)—
(4)
Other long-term liabilities (5) 36,926
 1,390
 2,903
 5,048
 27,585
 
  $2,337,243
 $151,277
 $200,693
 $158,636
 $1,673,879
 
 ________________________________________
(1)The interest payments presented above include the accrued interest payable on our long-term debt as of December 31, 2018 as well as future payments calculated using the long-term debt’s fixed rates, stated maturity dates, and principal amounts outstanding as of December 31, 2018.  See Note 3 to the Consolidated Financial Statements for additional information regarding our debt.
(2)Operating leases include various lease commitments for commercial real estate, which consists primarily of office space, and compressor equipment.
(3)Of the total Unconditional purchase obligations, $36.0 million represents obligations for the purchase of sand for well completions and $27.8 million represents obligations for firm transportation agreements for gas pipeline capacity. 
(4)We have excluded the presentation of the timing of the cash flows associated with our long-term asset retirement obligations because we cannot make a reasonably reliable estimate of the future period of cash settlement.  The long-term asset retirement obligation is included in the total asset retirement obligation presented. 
(5)Other long-term liabilities include contractual obligations associated with our employee supplemental savings plan, gas balancing liabilities, and other miscellaneous liabilities. All of these liabilities are accrued on our Consolidated Balance Sheet. The current portion associated with these long-term liabilities is also presented in the table above.
The following discusses various commercial commitments that we have drillingmade that may include potential future cash payments if we fail to meet various performance obligations.  These are not reflected in the table above. 
At December 31, 2018, we had estimated commitments of $157.5approximately: (i) $498.3 million consisting of obligations to finish drilling, completing, or performing other work on wells and completing wellsvarious other infrastructure projects in progress at December 31, 2016.

(3)         We have not included the long-term asset retirement obligations because we are not ableand (ii) $24.9 million to precisely predict the timingfinish gathering system construction in progress. 


58
Table of these amounts.

(4)         Other includes the estimated value of our commitments associated with our benefit obligations, derivative obligations, and other miscellaneous commitments.

Contents



At December 31, 2016,2018, we had firm sales contracts to deliver approximately 46.4316.9 Bcf of natural gas over the next twenty-two months.6.1 years.  If we do not deliver this gas, is not delivered, our estimated financial commitment, calculated using the January 2019 index price, would be approximately $164.8$814.7 million.  ThisThe value of this commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next ten9.0 years.  If nowe do not deliver the committed gas is delivered,or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2018, would be approximately $220.0$336.0 million.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments in connectionassociated with agreements to reimburse connection costs to various pipelines.  TheIf we do not deliver this gas, the estimated maximum amount that would be payable if no gas is deliveredunder these commitments, calculated as of December 31, 2018, would be approximately $7.9$57.3 million.  Of this total, we have accrued a liability of $2.1 million.  We may$2.5 million representing the estimated amount we will have additional liabilities associated with these delivery commitments in the future depending on our production levels and drilling results.

We have other various transportation, delivery, and facilities commitments in the normal course of business, which approximate $35.7 million. We currently anticipate meeting these obligations.

to pay due to insufficient forecasted volumes at particular connection points.

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

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

2017 Outlook

For 2017, our total production is projected to average 1.06 — 1.11 Bcfe per day, an increase of 13% at the midpoint from 2016 production levels.  First quarter 2017 production is expected to average 1.01 — 1.05 Bcfe per day.  Oil production in the first quarter is expected to increase approximately 10% from fourth quarter 2016 levels, with natural gas and NGL production expected to increase 4 — 5% sequentially.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Discussion and analysis of our financial condition and results of operation are based on our Consolidated Financial Statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP.America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. We analyze and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

A complete list of our

Our significant accounting policies are described in Note 1 to our Consolidated Financial Statements in Item 8 of this report.Statements. We have identified the following policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management.

Oil and Gas Reserves

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time due to numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

At year-end 2016, 21%2018, 15% of our total proved reserves are categorized as proved undeveloped reserves, or PUDs.reserves. Our reserve engineers review and revise these reserve estimates regularly, as new information becomes available.

We use the units-of-production method to amortize the cost associated with our oil and gas properties. Changes in estimates of reserve quantities and commodity prices will cause corresponding changes in depletion expense, or in some cases, a full cost ceiling impairment charge in the period of the revision. See Full Cost Accounting below for further information regarding the ceiling limitation calculation. See SUPPLEMENTAL INFORMATION ON OIL AND GAS INFORMATIONPRODUCING ACTIVITIES (UNAUDITED) in Item 8 of this report for additional reserve data.


59
Table of Contents


Full Cost Accounting

We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also are capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Companies that follow

Under the full cost method of accounting, methodwe are required to make aperform quarterly ceiling test calculation. Thiscalculations to test requires companies to record an impairment to the extent that total capitalized costs forour oil and gas properties (netfor possible impairment.  If the net capitalized cost of accumulated DD&Aour oil and all related deferredgas properties, as adjusted for income taxes) exceedtaxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum ofof: (i) the present value discounted at 10% of estimated future net cash flowsrevenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (iv) all related tax effects.as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Revenue calculations used to estimateEstimated future net cash flows from proved reservesrevenues are determined based on the unweightedtrailing twelve-month average first-day-of-the-month commodity price for the prior 12 months. Changes inprices and estimated proved reserve estimates (including those based upon quantity revisions or changes in commodity price) will cause corresponding changes to the full costquantities, operating costs, and capital expenditures.
The quarterly ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be expensed.  Any impairment of oil and gas propertiestest is not reversible at a later date.

Quarterly ceiling tests are primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes.  For eachIf pricing conditions decline, or if there is a negative impact on one or more of the first three quartersother components of 2016, the carrying value of our oil and gas properties subject to thecalculation, we may incur full cost ceiling test exceeded theimpairments in future quarters.  The calculated value of the ceiling limitation and we recognized aggregate impairments of $757.7 million ($481.4 million, net of tax).  These impairments resulted primarily from the impact of decreases in the 12-month average trailing prices for oil, natural gas and NGLs utilized in determining the future net cash flows from proved reserves. At December 31, 2016, 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 approximately 7% or more in the value of the ceiling limitation would have resulted in an impairment.  Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation.  See Operating costs and expenses above for a complete discussion of our 2016 ceiling impairments. See Note 1 to our Consolidated Financial statements in Item 8 of this report for information regarding the effect of a ceiling impairment on our depletion rate.

The ceiling limitation calculation is not intended to be indicative of the fair marketvalue of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.

  Any impairment of oil and gas properties is not reversible at a later date. 

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, and commodity prices, and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes.
The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. We first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If goodwill is determined to be impaired, then it is written down to a calculated fair value by charging the impairment to expense.

We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at December 31, 2016, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become  unfavorable.

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies to determine if we should record losses.  Actual costs can vary from our estimates for a variety of reasons.  See Note 10 to the Consolidated Financial Statements in Item 8 of this report for further information regarding litigation and other commitments and contingencies.

At December 31, 2016, we had not made any material accruals related to environmental remediation costs. However, we may be required to make such estimates in future periods if applicable laws and regulations change or if the interpretation or administration of laws and regulations change. Other factors, such as unanticipated construction problems or identification of areas of contaminated soil or groundwater, could also cause us to accrue for such costs.

Asset Retirement Obligation

Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset or depleted using the units-of-production method.

Asset retirement liability is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 8 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our asset retirement obligations.

Income Taxes

Our oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the tax asset would be reduced by a valuation allowance.  Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

The company

We regularly assessesassess and, if required, establishesestablish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our income taxes.



60
Table of Contents


Recently Issued Accounting Standards

See Note 1 Basis of Presentation and Summary of Significant Accounting Policies — Recently Issued Accounting Standards, to the Consolidated Financial Statements in Item 8 of this report for a discussion of recent accounting pronouncements and their anticipated effect on our business.


ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market

We are exposed to market risk refers toincluding 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, gas, and NGL production. The prices we receive for our production are based on prevailing market conditions and are influenced by many factors that are beyond our control. Pricing for oil, gas, and NGL production has been volatile and unpredictable. Oil sales contributed 52% ofDuring 2018, our total production revenue was comprised of 61% oil sales, 18% gas sales, and 21% NGL sales. The following table shows how hypothetical changes in the realized prices we receive for 2016. Gas and NGLour commodity sales accounted for 32% and 16%, respectively, of our 2016 production revenue. A $1.00 per barrel change in our realized oil price would have resulted in a $16.5 million change in revenues. A $0.10 per Mcf change in our realized gas price would have resulted in a $16.8 million change in our gas revenues. A $1.00 per barrel change in NGL prices would have changed revenues by $14.2 million.impacted revenue for the periods indicated. See MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Market Conditions in Item 7 of this report for further information.

information regarding prices.


Impact on Revenue
Change in Realized PriceYear Ended
December 31, 2018
(in thousands)
Oil± $1.00per barrel± $24,710
Gas± $0.10per Mcf± $20,584
NGL± $1.00per barrel± $21,994
± $67,288

We periodically enter into financial derivative contracts to hedge a portion of our price risk associated with our future oil and gas production. At December 31, 2016,2018, we had oil and gas collarsderivatives covering a portion of our 20172019 and 20182020 production, which were recorded as shortcurrent and long-termnon-current assets and liabilities. TheAt December 31, 2018, these derivatives had a gross asset fair value liability of our oil and gas collars was $29.0$111.2 million and $23.0 million, respectively.a gross liability fair value of $29.9 million. See Note 4 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our derivative instruments.

While these contracts limit the downside risk of adverse price movements, they may also limit future revenuescash flow from favorable price movements. For the oil contracts described above, aThe following table shows how hypothetical $1.00 changechanges in the price below or above the forward priceprices used to calculate the fair value of our derivatives would result in a decrease of $4.8 million or an increase of $5.0 million, respectively, tohave impacted the fair value liabilityas of the derivatives at December 31, 2016.  For the gas contracts described above, a hypothetical $0.10 change in the price below or above the forward price used to calculate the fair value would result in a decrease of $5.1 million or an increase of $5.3 million, respectively, to the fair value liability of the derivatives at December 31, 2016.

2018.

    Impact on Fair Value
  Change in Forward Price December 31, 2018
    (in thousands)
Oil -$1.00 $7,718
Oil +$1.00 $(7,539)
Gas -$0.10 $5,670
Gas +$0.10 $(5,606)
Interest Rate Risk

At December 31, 2016,2018, our long-term debt consisted of $750 million in 5.875%of 4.375% senior notes that will mature on May 1, 2022 and $750 million in 4.375% seniorunsecured notes that will mature on June 1, 2024.2024 and $750 million of 3.90% senior unsecured notes that will mature on May 15, 2027. Because all of our outstanding long-term debt is at a fixed rate, we consider our interest rate exposure to be minimal. 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 5 to the Consolidated Financial Statements in Item 8 of this report for additional information regarding our debt.



61

Table of Contents


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CIMAREX ENERGY CO.

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES

Page

Page
Report of Independent Registered Public Accounting Firm for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

66

63

Consolidated balance sheetsBalance Sheets as of December 31, 20162018 and 20152017

67

64

Consolidated statementsStatements of operationsOperations and comprehensive income (loss)Comprehensive Income (Loss) for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

68

65

Consolidated statementsStatements of cash flowsCash Flows for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

69

66

Consolidated statementsStatements of stockholders’ equityStockholders’ Equity for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

70

67

Notes to consolidated financial statementsConsolidated Financial Statements

Note 1 — Basis of Presentation and Summary of Significant Accounting Policies

71

68

Note 2 — Capital Stock

78

73

Note 3 — Long-termLong-Term Debt

79

73

Note 4 — Derivative Instruments/HedgingInstruments

80

75

Note 5 — Fair Value Measurements

82

79

Note 6 — Stock-Based and Other Compensation

84

80

Note 7 — Earnings (loss)(Loss) per Share

87

85

Note 8 — Asset Retirement Obligations

87

86

Note 9 — Income Taxes

88

86

Note 10 — Commitments and Contingencies

89

88

Note 11 — Related Party Transactions

90

89

Note 12 — Property Sales and Acquisitions

90

Note 13 — Supplemental Cash Flow Information

91

89

Note 13 — Acquisitions and Divestitures

90

Supplemental information to consolidated financial statements

Supplemental oil and gas information (Unaudited)Information to Consolidated Financial Statements

92

Supplemental quarterly financial dataInformation on Oil and Gas Producing Activities (Unaudited)

91
Supplemental Quarterly Financial Data (Unaudited)
97

All other supplemental information and schedules have been omitted because they are not applicable or the information required is shown in the consolidated financial statements or related notes thereto.



62

Table of Contents






Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors and Stockholders
Cimarex Energy Co.:

Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Cimarex Energy Co. and subsidiaries (the Company)(“the Company”) as of December 31, 20162018 and 2015, and2017, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-yearthree‑year period ended December 31, 2016.  2018, and the related notes (collectively, “the consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2019 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement.  An audit includesmisstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the consolidated financial statements. An auditOur audits also includes assessingincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cimarex Energy Co. and subsidiaries


KPMG LLP
We have served as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cimarex Energy Co. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2017, except for the restatement as to the effectiveness of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017, expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

KPMG LLP

auditor since 2002.

Denver, Colorado
February 24, 2017, except for the immaterial error correction to the consolidated financial statements discussed in Note 1 and the restatement as to the effectiveness20, 2019


63
Table of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017

Contents



CIMAREX ENERGY CO.

CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share information)

 

 

December 31,

 

 

 

2016

 

2015

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

652,876

 

$

779,382

 

Accounts receivable:

 

 

 

 

 

Trade, net of allowance

 

42,287

 

81,888

 

Oil and gas sales, net of allowance

 

217,395

 

136,537

 

Gas gathering, processing, and marketing, net of allowance

 

14,888

 

6,935

 

Other

 

27

 

38

 

Oil and gas well equipment and supplies

 

33,342

 

54,579

 

Derivative instruments

 

—

 

10,745

 

Prepaid expenses

 

7,335

 

7,036

 

Other current assets

 

1,154

 

790

 

Total current assets

 

969,304

 

1,077,930

 

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

 

 

 

 

 

Proved properties

 

16,225,495

 

15,546,948

 

Unproved properties and properties under development, not being amortized

 

478,277

 

440,166

 

 

 

16,703,772

 

15,987,114

 

Less—accumulated depreciation, depletion and amortization and impairment

 

(14,349,505

)

(13,245,832

)

Net oil and gas properties

 

2,354,267

 

2,741,282

 

Fixed assets, net of accumulated depreciation of $246,901 and $207,173

 

205,465

 

230,009

 

Goodwill

 

620,232

 

620,232

 

Deferred income taxes

 

55,835

 

—

 

Derivative instruments

 

—

 

501

 

Other assets, net

 

32,621

 

38,468

 

 

 

$

4,237,724

 

$

4,708,422

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable:

 

 

 

 

 

Trade

 

$

49,163

 

$

53,384

 

Gas gathering, processing, and marketing

 

25,323

 

13,431

 

Accrued liabilities:

 

 

 

 

 

Exploration and development

 

82,320

 

56,721

 

Taxes other than income

 

18,766

 

17,545

 

Other

 

177,695

 

173,242

 

Derivative instruments

 

49,370

 

—

 

Revenue payable

 

119,715

 

95,744

 

Total current liabilities

 

522,352

 

410,067

 

Long-term debt:

 

 

 

 

 

Principal

 

1,500,000

 

1,500,000

 

Less—unamortized debt issuance costs

 

(12,061

)

(14,380

)

Long-term debt, net

 

1,487,939

 

1,485,620

 

Deferred income taxes

 

—

 

157,162

 

Asset retirement obligation

 

140,770

 

153,857

 

Derivative instruments

 

2,570

 

—

 

Other liabilities

 

41,104

 

43,359

 

Total liabilities

 

2,194,735

 

2,250,065

 

Commitments and contingencies (Note 10)

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

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

 

—

 

—

 

Common stock, $0.01 par value, 200,000,000 shares authorized, 95,123,525 and 94,820,570 shares issued, respectively

 

951

 

948

 

Paid-in capital

 

2,763,452

 

2,762,976

 

Retained earnings (accumulated deficit)

 

(722,359

)

(306,008

)

Accumulated other comprehensive income

 

945

 

441

 

 

 

2,042,989

 

2,458,357

 

 

 

$

4,237,724

 

$

4,708,422

 

The


 December 31,
 2018 2017
Assets 
  
Current assets: 
  
Cash and cash equivalents$800,666
 $400,534
Accounts receivable, net of allowance: 
  
Trade122,065
 100,356
Oil and gas sales315,063
 344,552
Gas gathering, processing, and marketing17,072
 15,266
Oil and gas well equipment and supplies55,553
 49,722
Derivative instruments101,939
 15,151
Prepaid expenses7,554
 8,518
Other current assets4,227
 1,536
Total current assets1,424,139
 935,635
Oil and gas properties at cost, using the full cost method of accounting: 
  
Proved properties18,566,757
 17,513,460
Unproved properties and properties under development, not being amortized436,325
 476,903
 19,003,082
 17,990,363
Less—accumulated depreciation, depletion, amortization, and impairment(15,287,752) (14,748,833)
Net oil and gas properties3,715,330
 3,241,530
Fixed assets, net of accumulated depreciation of $324,631 and $290,114, respectively257,686
 210,922
Goodwill620,232
 620,232
Derivative instruments9,246
 2,086
Other assets35,451
 32,234
 $6,062,084
 $5,042,639
Liabilities and Stockholders’ Equity 
  
Current liabilities: 
  
Accounts payable: 
  
Trade$76,927
 $68,883
Gas gathering, processing, and marketing29,887
 29,503
Accrued liabilities: 
  
Exploration and development124,674
 115,762
Taxes other than income33,622
 23,687
Other221,159
 212,400
Derivative instruments27,627
 42,066
Revenue payable194,811
 187,273
Total current liabilities708,707
 679,574
Long-term debt: 
  
Principal1,500,000
 1,500,000
Less—unamortized debt issuance costs and discount(11,446) (13,080)
Long-term debt, net1,488,554
 1,486,920
Deferred income taxes334,473
 101,618
Asset retirement obligation152,758
 158,421
Derivative instruments2,267
 4,268
Other liabilities45,539
 43,560
Total liabilities2,732,298
 2,474,361
Commitments and contingencies (Note 10)

 

Stockholders’ equity: 
  
Preferred stock, $0.01 par value, 15,000,000 shares authorized, no shares issued—
 —
Common stock, $0.01 par value, 200,000,000 shares authorized, 95,755,797 and 95,437,434 shares issued, respectively958
 954
Additional paid-in capital2,785,188
 2,764,384
Retained earnings (accumulated deficit)542,885
 (199,259)
Accumulated other comprehensive income755
 2,199
Total stockholders’ equity3,329,786
 2,568,278
 $6,062,084
 $5,042,639



See accompanying notes are an integral partto Consolidated Financial Statements.

64
Table of these consolidated financial statements.

Contents



CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in thousands, except per share data)

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

632,934

 

$

809,664

 

$

1,308,958

 

Gas sales

 

388,786

 

428,227

 

687,930

 

NGL sales

 

199,498

 

179,647

 

375,941

 

Gas gathering and other

 

36,033

 

34,688

 

49,602

 

Gas marketing, net of related costs of $122,655, $144,673 and $256,836 respectively

 

94

 

393

 

1,745

 

 

 

1,257,345

 

1,452,619

 

2,424,176

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

757,670

 

4,033,295

 

—

 

Depreciation, depletion and amortization

 

392,348

 

731,460

 

775,577

 

Asset retirement obligation

 

7,828

 

9,121

 

10,082

 

Production

 

232,002

 

299,374

 

342,304

 

Transportation, processing, and other operating

 

190,725

 

182,362

 

195,414

 

Gas gathering and other

 

31,785

 

38,138

 

35,113

 

Taxes other than income

 

61,946

 

84,764

 

128,793

 

General and administrative

 

73,901

 

74,688

 

81,160

 

Stock compensation

 

24,523

 

19,559

 

15,001

 

(Gain) loss on derivative instruments, net

 

55,749

 

(11,246

)

(3,762

)

Other operating expense, net

 

755

 

856

 

116

 

 

 

1,829,232

 

5,462,371

 

1,579,798

 

Operating income (loss)

 

(571,887

)

(4,009,752

)

844,378

 

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

83,272

 

85,746

 

72,865

 

Capitalized interest

 

(21,248

)

(30,589

)

(35,925

)

Other, net

 

(10,707

)

(13,576

)

(28,907

)

Income (loss) before income tax

 

(623,204

)

(4,051,333

)

836,345

 

Income tax expense (benefit)

 

(214,401

)

(1,471,729

)

309,847

 

Net income (loss)

 

$

(408,803

)

$

(2,579,604

)

$

526,498

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

0.64

 

$

0.64

 

Undistributed

 

(4.70

)

(28.39

)

5.37

 

 

 

$

(4.38

)

$

(27.75

)

$

6.01

 

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

0.64

 

$

0.64

 

Undistributed

 

(4.70

)

(28.39

)

5.36

 

 

 

$

(4.38

)

$

(27.75

)

$

6.00

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(408,803

)

$

(2,579,604

)

$

526,498

 

Other comprehensive income (loss):

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

504

 

(661

)

(87

)

Total comprehensive income (loss)

 

$

(408,299

)

$

(2,580,265

)

$

526,411

 

Theinformation)

 Years Ended December 31,
 2018 2017 2016
Revenues: 
  
  
Oil sales$1,398,813
 $981,646
 $632,934
Gas and NGL sales898,832
 892,357
 588,284
Gas gathering and other41,180
 43,751
 36,033
Gas marketing192
 495
 94
 2,339,017
 1,918,249
 1,257,345
Costs and expenses: 
  
  
Impairment of oil and gas properties—
 —
 757,670
Depreciation, depletion, and amortization590,473
 446,031
 392,348
Asset retirement obligation7,142
 15,624
 7,828
Production293,213
 262,180
 232,002
Transportation, processing, and other operating200,802
 231,640
 190,725
Gas gathering and other41,964
 35,840
 31,785
Taxes other than income125,169
 89,864
 61,946
General and administrative80,850
 79,996
 73,901
Stock compensation22,895
 26,256
 24,523
(Gain) loss on derivative instruments, net(85,959) (21,210) 55,749
Other operating expense, net15,500
 1,314
 755
 1,292,049
 1,167,535
 1,829,232
Operating income (loss)1,046,968
 750,714
 (571,887)
Other (income) and expense: 
  
  
Interest expense68,224
 74,821
 83,272
Capitalized interest(20,855) (22,948) (21,248)
Loss on early extinguishment of debt—
 28,187
 —
Other, net(22,908) (11,342) (10,707)
Income (loss) before income tax1,022,507
 681,996
 (623,204)
Income tax expense (benefit)230,656
 187,667
 (214,401)
Net income (loss)$791,851
 $494,329
 $(408,803)
      
Earnings (loss) per share to common stockholders: 
  
  
Basic$8.32
 $5.19
 $(4.38)
Diluted$8.32
 $5.19
 $(4.38)
      
Comprehensive income (loss): 
  
  
Net income (loss)$791,851
 $494,329
 $(408,803)
Other comprehensive income (loss): 
  
  
Change in fair value of investments, net of tax of $(425), $106, and $289, respectively(1,444) 1,254
 504
Total comprehensive income (loss)$790,407
 $495,583
 $(408,299)





See accompanying notes are an integral partto Consolidated Financial Statements.

65
Table of these consolidated financial statements.

Contents



CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(408,803

)

$

(2,579,604

)

$

526,498

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairments and other valuation losses

 

757,670

 

4,033,295

 

—

 

Depreciation, depletion and amortization

 

392,348

 

731,460

 

775,577

 

Asset retirement obligation

 

7,828

 

9,121

 

10,082

 

Deferred income taxes

 

(213,286

)

(1,486,439

)

309,443

 

Stock compensation

 

24,523

 

19,559

 

15,001

 

(Gain) loss on derivative instruments, net

 

55,749

 

(11,246

)

(3,762

)

Settlements on derivative instruments

 

7,437

 

—

 

7,641

 

Changes in non-current assets and liabilities

 

3,867

 

23,230

 

(2,440

)

Other, net

 

1,805

 

4,206

 

(3,828

)

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

(49,340

)

186,699

 

(35,133

)

Other current assets

 

20,880

 

37,954

 

(25,428

)

Accounts payable and other current liabilities

 

(1,453

)

(276,735

)

45,714

 

Net cash provided by operating activities

 

599,225

 

691,500

 

1,619,365

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(699,558

)

(979,044

)

(2,108,250

)

Sales of oil and gas assets

 

21,487

 

39,853

 

449,981

 

Sales of other assets

 

7,889

 

1,178

 

8,413

 

Other capital expenditures

 

(22,228

)

(70,592

)

(90,611

)

Net cash used by investing activities

 

(692,410

)

(1,008,605

)

(1,740,467

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Net bank debt borrowings

 

—

 

—

 

(174,000

)

Proceeds from other long-term debt

 

—

 

—

 

750,000

 

Proceeds from sale of common stock

 

—

 

752,100

 

—

 

Financing and underwriting fees

 

(101

)

(24,633

)

(11,616

)

Dividends paid

 

(38,024

)

(58,281

)

(53,849

)

Proceeds from exercise of stock options and other

 

4,804

 

21,439

 

11,898

 

Net cash (used) provided by financing activities

 

(33,321

)

690,625

 

522,433

 

Net change in cash and cash equivalents

 

(126,506

)

373,520

 

401,331

 

Cash and cash equivalents at beginning of period

 

779,382

 

405,862

 

4,531

 

Cash and cash equivalents at end of period

 

$

652,876

 

$

779,382

 

$

405,862

 

The

 Years Ended December 31,
 2018 2017 2016
Cash flows from operating activities: 
  
  
Net income (loss)$791,851
 $494,329
 $(408,803)
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
  
Impairment of oil and gas properties—
 —
 757,670
Depreciation, depletion, and amortization590,473
 446,031
 392,348
Asset retirement obligation7,142
 15,624
 7,828
Deferred income taxes233,280
 190,479
 (213,286)
Stock compensation22,895
 26,256
 24,523
(Gain) loss on derivative instruments, net(85,959) (21,210) 55,749
Settlements on derivative instruments(24,429) (1,633) 7,437
Loss on early extinguishment of debt—
 28,187
 —
Changes in non-current assets and liabilities(1,779) 1,891
 3,867
Other, net105
 5,677
 1,805
Changes in operating assets and liabilities: 
  
  
Accounts receivable5,421
 (186,157) (49,340)
Other current assets(1,957) (17,931) 20,880
Accounts payable and other current liabilities13,951
 115,021
 25,171
Net cash provided by operating activities1,550,994
 1,096,564
 625,849
Cash flows from investing activities: 
  
  
Oil and gas capital expenditures(1,566,583) (1,233,126) (699,558)
Other capital expenditures(103,459) (45,352) (22,228)
Sales of oil and gas assets580,652
 11,680
 21,487
Sales of other assets3,772
 901
 7,889
Net cash used by investing activities(1,085,618) (1,265,897) (692,410)
Cash flows from financing activities: 
  
  
Borrowings of long-term debt—
 748,110
 —
Repayments of long-term debt—
 (750,000) —
Call premium, financing, and underwriting fees(100) (29,312) (101)
Dividends paid(55,243) (30,532) (38,024)
Employee withholding taxes paid upon the net settlement of equity-classified stock awards(12,142) (21,669) (26,624)
Proceeds from exercise of stock options2,241
 394
 4,804
Net cash used by financing activities(65,244) (83,009) (59,945)
Net change in cash and cash equivalents400,132
 (252,342) (126,506)
Cash and cash equivalents at beginning of period400,534
 652,876
 779,382
Cash and cash equivalents at end of period$800,666
 $400,534
 $652,876





See accompanying notes are an integral partto Consolidated Financial Statements.

66
Table of these consolidated financial statements.

Contents



CIMAREX ENERGY CO.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)

 

 

 

 

 

 

 

 

Retained

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

Earnings

 

Other

 

Total

 

 

 

Common Stock

 

Paid-in

 

(Accumulated

 

Comprehensive

 

Stockholders’

 

 

 

Shares

 

Amount

 

Capital

 

Deficit)

 

Income (loss)

 

Equity

 

Balance, December 31, 2013

 

87,152

 

$

872

 

$

1,970,113

 

$

1,862,075

 

$

1,189

 

$

3,834,249

 

Dividends

 

—

 

—

 

—

 

(55,664

)

—

 

(55,664

)

Net income

 

—

 

—

 

—

 

526,498

 

—

 

526,498

 

Unrealized change in fair value of investments, net of tax

 

—

 

—

 

—

 

—

 

(87

)

(87

)

Issuance of restricted stock awards

 

487

 

4

 

(4

)

—

 

—

 

—

 

Common stock reacquired and retired

 

(123

)

(1

)

(13,559

)

—

 

—

 

(13,560

)

Restricted stock forfeited and retired

 

(135

)

(1

)

1

 

—

 

—

 

—

 

Exercise of stock options

 

211

 

2

 

11,896

 

—

 

—

 

11,898

 

Stock-based compensation

 

—

 

—

 

28,633

 

—

 

—

 

28,633

 

Balance, December 31, 2014

 

87,592

 

$

876

 

$

1,997,080

 

$

2,332,909

 

$

1,102

 

$

4,331,967

 

Dividends

 

—

 

—

 

—

 

(59,313

)

—

 

(59,313

)

Net loss

 

—

 

—

 

—

 

(2,579,604

)

—

 

(2,579,604

)

Unrealized change in fair value of investments, net of tax

 

—

 

—

 

—

 

—

 

(661

)

(661

)

Issuance of common stock

 

6,900

 

69

 

729,468

 

—

 

—

 

729,537

 

Issuance of restricted stock awards

 

471

 

5

 

(5

)

—

 

—

 

—

 

Common stock reacquired and retired

 

(194

)

(2

)

(21,238

)

—

 

—

 

(21,240

)

Restricted stock forfeited and retired

 

(90

)

(1

)

1

 

—

 

—

 

—

 

Exercise of stock options

 

142

 

1

 

8,450

 

—

 

—

 

8,451

 

Stock-based compensation

 

—

 

—

 

36,232

 

—

 

—

 

36,232

 

Stock-based compensation tax benefit

 

—

 

—

 

12,988

 

—

 

—

 

12,988

 

Balance, December 31, 2015

 

94,821

 

$

948

 

$

2,762,976

 

$

(306,008

)

$

441

 

$

2,458,357

 

Dividends

 

—

 

—

 

—

 

(7,548

)

—

 

(7,548

)

Dividends in excess of retained earnings

 

—

 

—

 

(22,803

)

—

 

—

 

(22,803

)

Net loss

 

—

 

—

 

—

 

(408,803

)

—

 

(408,803

)

Unrealized change in fair value of investments, net of tax

 

—

 

—

 

—

 

—

 

504

 

504

 

Issuance of restricted stock awards

 

479

 

5

 

(5

)

—

 

—

 

—

 

Common stock reacquired and retired

 

(208

)

(3

)

(26,622

)

—

 

—

 

(26,625

)

Restricted stock forfeited and retired

 

(32

)

—

 

—

 

—

 

—

 

—

 

Exercise of stock options

 

64

 

1

 

4,803

 

—

 

—

 

4,804

 

Stock-based compensation

 

—

 

—

 

45,103

 

—

 

—

 

45,103

 

Balance, December 31, 2016

 

95,124

 

$

951

 

$

2,763,452

 

$

(722,359

)

$

945

 

$

2,042,989

 

The

       
Retained
Earnings (Accumulated Deficit)
 
Accumulated
Other Comprehensive Income (Loss)
 Total Stockholders’ Equity
 Common Stock Additional Paid-in Capital   
 Shares Amount    
Balance, December 31, 201594,821
 $948
 $2,762,976
 $(306,008) $441
 $2,458,357
Dividends paid on stock awards subsequently forfeited—
 —
 2
 35
 —
 37
Dividends declared ($0.32 per share)—
 —
 (22,805) (7,583) —
 (30,388)
Net loss—
 —
 —
 (408,803) —
 (408,803)
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 504
 504
Issuance of restricted stock awards479
 5
 (5) —
 —
 —
Common stock reacquired and retired(208) (3) (26,622) —
 —
 (26,625)
Restricted stock forfeited and retired(32) —
 —
 —
 —
 —
Exercise of stock options64
 1
 4,803
 —
 —
 4,804
Stock-based compensation—
 —
 45,103
 —
 —
 45,103
Balance, December 31, 201695,124
 951
 2,763,452
 (722,359) 945
 2,042,989
Dividends paid on stock awards subsequently forfeited—
 —
 11
 32
 —
 43
Dividends declared ($0.32 per share)—
 —
 (30,489) —
 —
 (30,489)
Net income—
 —
 —
 494,329
 —
 494,329
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 1,254
 1,254
Issuance of restricted stock awards552
 5
 (5) —
 —
 —
Common stock reacquired and retired(204) (2) (21,667) —
 —
 (21,669)
Restricted stock forfeited and retired(41) —
 —
 —
 —
 —
Exercise of stock options6
 —
 394
 —
 —
 394
Stock-based compensation—
 —
 48,321
 —
 —
 48,321
Cumulative effect adjustment of adopting ASU 2016-09 (Note 6)—
 —
 4,393
 28,739
 —
 33,132
Other—
 —
 (26) —
 —
 (26)
Balance, December 31, 201795,437
 954
 2,764,384
 (199,259) 2,199
 2,568,278
Dividends paid on stock awards subsequently forfeited—
 —
 34
 18
 —
 52
Dividends declared ($0.68 per share)—
 —
 (15,196) (49,725) —
 (64,921)
Net income—
 —
 —
 791,851
 —
 791,851
Unrealized change in fair value of investments, net of tax—
 —
 —
 —
 (1,444) (1,444)
Issuance of restricted stock awards593
 6
 (6) —
 —
 —
Common stock reacquired and retired(139) —
 (12,142) —
 —
 (12,142)
Restricted stock forfeited or canceled and retired(168) (2) 2
 —
 —
 —
Exercise of stock options33
 —
 2,241
 —
 —
 2,241
Stock-based compensation—
 —
 45,871
 —
 —
 45,871
Balance, December 31, 201895,756
 $958
 $2,785,188
 $542,885
 $755
 $3,329,786



See accompanying notes are an integral partto Consolidated Financial Statements.

67
Table of these consolidated financial statements.

Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cimarex Energy Co., a Delaware corporation, is an independent oil and gas exploration and production company. Our operations are mainly located in Texas, Oklahoma, and New Mexico.

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Our significant accounting policies are discussed below. The accounts of Cimarex and its subsidiaries are presented in the accompanying Consolidated Financial Statements. All intercompany accounts and transactions were eliminated in consolidation.

Certain amounts in the prior year financial statements have been reclassified to conform to the 2018 financial statement presentation.

Segment Information

We have determined that our business is comprised of only one segment because our gathering, processing, and marketing activities are ancillary to our production operations and are not separately managed.

operations.

Use of Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. The more significant areasAreas of significance requiring the use of management’s estimates and judgments relate toinclude the estimation of proved oil and gas reserves the use of these oil and gas reservesused in calculating depletion, depreciation and amortization (DD&A), the use of the estimatesestimation of future net revenues used in computing ceiling test limitations, and estimatesthe estimation of future abandonment obligations used in recording asset retirement obligations, and the assessment of goodwill.

  Estimates and judgments also are required in determining allowances for doubtful accounts, impairments of unproved properties and other assets, valuation of deferred tax assets, fair value measurements, and contingencies. We analyze our estimates and base them on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

Estimates and judgments are also required in determining the allowance for doubtful accounts, impairments of unproved properties and other assets, purchase price allocation, valuation of deferred tax assets, fair value measurements and commitments and contingencies. We analyze our estimates, including those related to oil, gas and NGL revenues, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. Cash equivalents are stated at cost, which approximates market value.

Oil and Gas Well Equipment and Supplies

We carry our inventory

Our oil and gas well equipment and supplies are valued at the lower of cost orand net realizable value, where net realizable value is based on estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. We performed an analysis of our oil and gas well equipment and supplies as of December 31, 2016, and no impairment was required.  However, the industry-wide declineDeclines in drilling operations has put downward pressure on the price of oil and gas well equipment and supplies.  Declinessupplies in future periods could cause us to recognize impairments

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

on these assets. An impairment would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.


68
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Oil and Gas Properties


We use the full cost method of accounting for our oil and gas operations. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the acquisition, exploration, and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Companies that follow

Under the full cost method of accounting, methodwe are required to makeperform quarterly ceiling test calculations. Thiscalculations to test requires companies to record an impairment to the extent that total capitalized costs forour oil and gas properties (netfor possible impairment.  If the net capitalized cost of accumulated DD&Aour oil and all related deferredgas properties, as adjusted for income taxes) exceedtaxes, exceeds the ceiling limitation, the excess is charged to expense.  The ceiling limitation is equal to the sum ofof: (i) the present value discounted at 10% of estimated future net cash flowsrevenues from proved reserves, (ii) the cost of properties not being amortized, and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and (iv) all related tax effects.as adjusted for income taxes.  We currently do not have any unproven properties that are being amortized. Revenue calculations used to estimateEstimated future net cash flows from proved reservesrevenues are determined based on trailing twelve-month average commodity prices and estimated proved reserve quantities, operating costs, and capital expenditures.
We did not recognize a ceiling test impairment during the unweighted average first-day-of-the-month prices foryears ended December 31, 2018 and 2017 because the prior 12 months.  If net capitalized costs exceed this limit, the excess is charged to expense.

At December 31, 2016, the carrying valuecost of our oil and gas properties, subject to the testas adjusted for income taxes, did not exceed the calculated value of the ceiling limitation and, therefore, we did not recognize an impairment.  However,limitation. At December 31, 2018, a decline of approximately 7% or more in the value of the ceiling limitation of approximately 24% or more would have resulted in an impairment. We did recognize impairments in the first three quarters of 2016 totaling $757.7 million ($481.4 million, net of tax).  For the year ended December 31, 2015,2016, full year impairments totaled $4.0 billion$757.7 million ($2.6 billion,481.4 million, net of tax). These impairments resulted primarily from the impact of decreases in the 12-monthtrailing twelve-month average trailing prices for oil, natural gas, and NGLs utilized in determining the future net cash flowsrevenues from proved reserves. The quarterly ceiling test is primarily impacted by commodity prices, changes in estimated reserve quantities, reserves produced, overall exploration and development costs, depletion expense, and deferred taxes.  If pricing conditions decline, or if there is a negative impact on one or more of the other components of the calculation, we willmay incur full cost ceiling test impairments in future quarters.  The calculated ceiling calculationlimitation is not intended to be indicative of the fair marketvalue of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and othervarious components of our balance sheet.  Any impairment of oil and gas properties is not reversible at a later date.

Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves. Changes in our estimate of proved reserve quantities, commodity prices, and impairment of oil and gas properties will cause corresponding changes in depletion expense in periods subsequent to these changes.

The capitalized costs of unproved properties, including those in wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually. Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.


Fixed Assets net

Fixed assets consist primarily of gathering and plant facilities, vehicles, airplanes, office furniture, and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from 3 to 30 years.



69
Table of Contents

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. We have one reporting unit for whichIn performing the goodwill test, we first assess qualitative factors to determine whether it is more likely than not (with a greater than 50% threshold) thatcompare the fair value of aour reporting unit is less thanwith its carrying amount. If the carrying amount as a basis for determining whether it is necessaryof the reporting unit were to perform the two-step goodwill impairment test. If goodwill is determined to be impaired then it is written down to a calculatedexceed its fair value, by chargingan impairment charge would be recognized in the impairmentamount of this excess, limited to expense.

the total amount of goodwill allocated to that reporting unit. We evaluate our goodwill for impairment in the fourth quarter of each year and whenever events or changes in circumstances indicate the possibility that goodwill may be impaired. Based upon our qualitative assessment at Decemberas of October 31, 2016,2018, goodwill was not impaired. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors become less favorable.

unfavorable.

Revenue Recognition

Oil, Gas, and NGL Sales
Effective January 1, 2018, we adopted the provisions of Accounting Standards Codification 606,

Revenue from Contracts with Customers (“ASC 606”), utilizing the modified retrospective approach, which we applied to contracts that were not completed as of that date. Because we utilized the modified retrospective approach, there was no impact to prior periods’ reported amounts. Application of ASC 606 has no impact on our net income or cash flows from operations; however, certain costs classified as Transportation, processing, and other operating in the statement of operations under prior accounting standards are now reflected as deductions from revenue under ASC 606. The following table presents the impact on our Oil sales, Gas sales, and NGL sales and on our Transportation, processing, and other operating costs from the application of ASC 606 in the current reporting period:

  Years Ended December 31,
  2018 2017 2016
(in thousands) Pre-
ASC 606 Adoption		 Impact of
ASC 606		 Post-
ASC 606 Adoption		 As Reported As Reported
Oil sales $1,398,813
 $—
 $1,398,813
 $981,646
 $632,934
Gas sales 425,233
 (16,482) 408,751
 516,936
 388,786
NGL sales 518,410
 (28,329) 490,081
 375,421
 199,498
Total oil, gas, and NGL sales $2,342,456
 $(44,811) $2,297,645
 $1,874,003
 $1,221,218
           
Transportation, processing, and other operating costs $245,613
 $(44,811) $200,802
 $231,640
 $190,725
Revenue is recordedrecognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale, and when collectability is deliveredprobable. All of our sales of oil, gas, and NGLs are made under contracts with customers, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. As of December 31, 2018, we had open contracts with customers with terms of one month to multiple years, as well as “evergreen” contracts that renew on a periodic basis if not canceled by us or the customer. Performance obligations under our contracts with customers are typically satisfied at a fixed point-in-time through monthly delivery of oil, gas, and/or determinable price, title has transferredNGLs. Our contracts with customers typically require payment within one month of delivery.
Our gas and collectabilityNGLs are sold under a limited number of contract structure types common in our industry. Under these contracts the gas and its components, including NGLs, may be sold to a single purchaser or the residue gas and NGLs may be sold to separate purchasers. Regardless of the contract structure type, the terms of these contracts compensate us for the value of the residue gas and NGLs at current market prices for each product, and are disaggregated in the tables above on that basis. Our oil typically is reasonably assured.  There is a ready marketsold at specific delivery points under contract terms that also are common in our industry.

70
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Gas Gathering
When we transport and/or process third-party gas associated with our equity gas, we recognize revenue for our products and sales occur soon after production.

the fees charged to third-parties for such services.

Gas Marketing Sales

We

When we market and sell natural gas for working interest owners, we act as agent under short termshort-term sales and supply agreements and may earn a fee for such services. Revenues from such services are recognized as gas is delivered and are reflected netdelivered.
Gas Imbalances
Revenue from the sale of gas purchases on the consolidated statements of operations and comprehensive income (loss).

Gas Imbalances

We use the sales method of accounting for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold. Gas reservessold by us. If our aggregate sales volumes for a well are adjustedgreater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are sufficient quantities of natural gas to make up an imbalance. A liability is established in situations where there are insufficient proved reserves available to make-up anthe overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

General and Administrative Expenses

General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Cimarex and net of amounts capitalized pursuant to the full cost method of accounting.

Derivatives

Our derivative contracts are recorded on the balance sheet at fair value. Our firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. See Note 4 for additional information regarding our derivative instruments.

Income Taxes

We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. We classify all deferred tax assets and liabilities as noncurrent.non-current. We routinely assess the realizability of theour deferred tax assets. We routinely assess the realizability of our deferred tax assets. Numerous judgments and assumptions are inherent in this assessment, including the determination of future taxable income, which is affected by factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws. If we conclude that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We regularly assess and, if required, establish accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions where the company operates. See Note 9 for additional information regarding our income taxes.

Contingencies


A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and determine when we should record losses for these items based on information available to us. See Note 10 for additional information regarding our contingencies.

Asset Retirement Obligations

We recognize the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount

71
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. SubsequentIn periods subsequent to the initial measurement theof an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is requiredrecognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to be accreted each period.the carrying amount of the liability. 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 current portionsportion of theour asset retirement obligations areis recorded in “Accrued liabilities — Other” in the accompanying consolidated balance sheets and expenditurescash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note 8 for additional information regarding our asset retirement obligations.

Stock-based Compensation

We recognize compensation cost related to all stock-based awards in the financial statements based on their estimated grant-dategrant date fair value. We grant various types of stock-based awards including stock options, restricted stock (including awards with service-based vesting and market condition-based vesting provisions), and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. The fair value of the market condition-based restricted stock is based on the grant-dategrant date market value of the award utilizing a statistical analysis. Compensation cost is recognized ratably over the applicable vesting period. To the extent compensation cost relates to employees directly involved in oil and gas acquisition, exploration, and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized as stock compensation expense. See Note 6 for additional information regarding our stock-based compensation.

Earnings (loss)(Loss) per Share

We calculate earnings (loss) per share recognizing that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are “participating securities” and, therefore, should be included in computing earnings per share using the two-class earnings allocation method. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our unvested share basedshare-based payment awards, consisting of restricted stock and units, qualify as participating securities. See Note 7 for additional information regarding our earnings per share.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606).  In July 2015, the FASB deferred the effective date by one year to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

period. Early adoption is permitted, but not before the original effective date of reporting periods beginning after December 15, 2016.  The new revenue standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The guidance in this update supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification.  Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach.  We intend to adopt this standard on January 1, 2018, utilizing a modified retrospective approach.  Management does not believe the effect of adoption will be material to our financial statements because we follow the sales method of accounting for our oil, gas and NGL production, which is generally consistent with the revenue recognition provisions of the new standard.  However, we anticipate the new standard will result in more robust footnote disclosures.  We cannot currently determine the extent of the new footnote disclosures as further clarification is needed for certain practices common to the industry.


In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842).  The key provision of this ASUTopic 842 is that a lessee must recognize (i) liabilities to make lease payments and (ii) right-of-use assets on its balance sheet.  The ASU permits lessees to make a policy election to not recognize lease assets and liabilities for leases with terms of less than twelve months.  Under current GAAP, a determination of whether a lease is a capital or operating lease is made at lease inception and no assets or liabilities are recognized for operating leases.  Under this ASU,Topic 842, the determination to be made at the inception of a contract is whether the contract is, or contains, a lease.  Leases convey the right to control the use of an identified asset in exchange for consideration.  Only the lease components of a contract must be accounted for in accordance with this ASU.Topic 842.  Non-lease components, such as activities that transfer a good or service to the customer, shall be accounted for under other applicable Topics.  An entity may make a policy election to not separate lease and non-lease components and account for the non-lease components together with the lease components as a single lease component.  This ASUTopic 842 retains a distinction between finance and operating leases concerning the recognition and presentation of the expense and payments related to leases in the statements of operations and comprehensive income and cash flows, however, both types of leases require the recognition of assets and liabilities on the balance sheet.  This ASUTopic 842 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. Upon transition, lesseesWe will be requiredadopt Topic 842 effective January 1, 2019, recognizing a cumulative-effect adjustment to recognize and measure leases at the beginningopening balance of the earliest period presented using a modified retrospective approach.  While we areretained earnings in the processperiod of evaluating the potential impactadoption. The primary effect of adopting this guidance, the primary effectadoption will be to record assets and obligationsliabilities for contracts currently recognizedaccounted for as operating leases.  We do not intend to adopt the standard early.leases, such as leases for office space, compressors, and other equipment.


72
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


In March 2016,January 2018, the FASB issued ASU 2016-09, Improvements2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in this ASU are effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The standard contains various amendments, and specifies whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. We will adopt ASU 2016-09 effective January 1, 2017. The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures will be adopted using a modified retrospective method. In accordance with this method, we expect to record a cumulative-effect adjustment on that date relating to those amendments, representing an increase to beginning Deferred income taxes of approximately $33 million, a reduction to beginning Accumulated deficit of approximately $31 million and an increase to beginning Paid-in capital of approximately $2 million. The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to tax withholdings on the net settlement of equity-classified awards will be adopted using a retrospective method. In accordance with this method, we estimate that Net cash provided by operating activities would have increased and Net cash (used) provided by financing activities would have decreased by approximately $27 million, $34 million and $14 million, for the years ended December 31, 2016, 2015 and 2014, respectively.Topic 842

In January 2017, the FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350)—Simplifying the Test for Goodwill Impairment. This ASU eliminates step two fromprovides an optional transition practical expedient to not evaluate under Topic 842 (discussed above) existing or expired land easements that were not previously accounted for as leases under the goodwill impairment test.  Under current leases guidance ifin Topic 840. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the fair value of the reporting unit is less than its carrying amount (step 1 of the goodwill impairment test), entities must complete step two to determine the impairment amount, if any.  Under step two, the impairment amount is

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

determined by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination, and comparing it to the carrying amount of the goodwill.  Under this ASU, the impairment amount is the amount by which the carrying amount of the reporting unit exceeds the reporting unit’s fair value, with the amount of impairment not to exceed the carrying amount of the goodwill.  This ASU retains the option to qualitatively assess whether it is more likely than notdate that the fair valueentity adopts Topic 842. Under the full cost method of the reporting unit is less than its carrying amount in orderaccounting, we capitalize to determine if it is necessary to initiate step 1.  This ASU is effective for annual or any interim goodwill impairment tests in the fiscal years beginning after December 15, 2019, with early adoption permitted for testing dates after January 1, 2017.  The implementation of this ASU will affect the amount of goodwill impairment we record, if any.  We adopted this ASU on January 1, 2017, and will apply its provisions in future periods if we determine our goodwill has been impaired.

Subsequent Events

The accompanying financial disclosures include an evaluation of subsequent events through the date of this filing.

Correction of Previously Issued Consolidated Financial Statements

In the course of preparing our consolidated financial statements for the quarter ended March 31, 2017, we identified an error in the quarterly ceiling test calculations used in prior periods to test our oil and gas properties for possible impairment. Specifically,all property acquisition, exploration, and development costs, which include the calculations did not properly consider the company’s tax net operating loss carryforwards in the calculation of the capitalized costs of net oilland easements. We plan to elect this practical expedient and gas propertiescontinue to be testedapply our current accounting policy to account for impairment. This error had the effectland easements that existed before our adoption of incorrectly reporting impairment amounts in prior periods, which resulted in incorrectly reporting depletion expenseTopic 842 and income tax expense (benefit) in prior periods.

After considering the guidance in Staff Accounting Bulletin (“SAB”) No. 99, Materiality, and Accounting Standards Codification 250, Accounting Changes and Error Corrections, we evaluated the materialitywill evaluate new or modified land easements under Topic 842 upon our adoption of these amounts quantitatively and qualitatively and concluded that the error was not material to any of the company’s prior annual or interim period financial statements.  The consolidated financial statements as of and for the years ended December 31, 2016, 2015 and 2014, and the unaudited interim period consolidated financial statements within the years ended December 31, 2016 and 2015 in this Form 10-K/A, have been revised in accordance with SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, in order to reflect these corrections. The corrections reflect the adjustments to impairment amounts, depletion expense and income tax expense (benefit) described above, as well as the resulting adjustments to deferred income taxes, accumulated depreciation, depletion and amortization and impairment, and retained earnings (accumulated deficit). Retained earnings as of December 31, 2013 reflected in the accompanying consolidated statements of stockholders’ equity has been reduced by $188.0 million from its previously reported balance of $2.05 billion to the corrected balance of $1.86 billion to reflect the impact of correcting the errors discussed above for the years ended December 31, 2013 ($102.9 million) and 2012 ($85.1 million). Correction of the errors discussed above impacted certain non-cash line items within the operating cash flow section of the consolidated statements of cash flows; however, the corrections did not change previously reported Net cash provided by operating activities for any period.Topic 842.

In addition to correcting the consolidated financial statements, we have also corrected the Supplemental Quarterly Financial Data (Unaudited) and the following Notes for the effects of the errors discussed above:

· Note 1 — Basis of Presentation and Summary of Significant Accounting Policies

· Note 7 — Earnings (Loss) Per Share

· Note 9 — Income Taxes

The following tables present the effect of the corrections on selected line items from the previously reported consolidated financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Consolidated Balance Sheet
December 31, 2016

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Accumulated depreciation, depletion and amortization and impairment

 

$

(13,849,701

)

$

(499,804

)

$

(14,349,505

)

Net oil and gas properties

 

$

2,854,071

 

$

(499,804

)

$

2,354,267

 

Total assets

 

$

4,681,693

 

$

(443,969

)

$

4,237,724

 

Deferred income taxes — (asset) liability

 

$

126,894

 

$

(182,729

)

$

(55,835

)

Total liabilities

 

$

2,321,629

 

$

(126,894

)

$

2,194,735

 

Retained earnings (accumulated deficit)

 

$

(405,284

)

$

(317,075

)

$

(722,359

)

Total stockholders’ equity

 

$

2,360,064

 

$

(317,075

)

$

2,042,989

 

Total liabilities and stockholders’ equity

 

$

4,681,693

 

$

(443,969

)

$

4,237,724

 

 

 

Consolidated Balance Sheet
December 31, 2015

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Accumulated depreciation, depletion and amortization and impairment

 

$

(12,710,968

)

$

(534,864

)

$

(13,245,832

)

Net oil and gas properties

 

$

3,276,146

 

$

(534,864

)

$

2,741,282

 

Total assets

 

$

5,243,286

 

$

(534,864

)

$

4,708,422

 

Deferred income tax (asset) liability

 

$

352,705

 

$

(195,543

)

$

157,162

 

Total liabilities

 

$

2,445,608

 

$

(195,543

)

$

2,250,065

 

Retained earnings (accumulated deficit)

 

$

33,313

 

$

(339,321

)

$

(306,008

)

Total stockholders’ equity

 

$

2,797,678

 

$

(339,321

)

$

2,458,357

 

Total liabilities and stockholders’ equity

 

$

5,243,286

 

$

(534,864

)

$

4,708,422

 

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Impairment of oil and gas properties

 

$

719,142

 

$

38,528

 

$

757,670

 

Depreciation, depletion and amortization

 

$

465,936

 

$

(73,588

)

$

392,348

 

Total operating expenses

 

$

1,864,292

 

$

(35,060

)

$

1,829,232

 

Operating income (loss)

 

$

(606,947

)

$

35,060

 

$

(571,887

)

Income (loss) before income tax

 

$

(658,264

)

$

35,060

 

$

(623,204

)

Income tax expense (benefit)

 

$

(227,215

)

$

12,814

 

$

(214,401

)

Net income (loss)

 

$

(431,049

)

$

22,246

 

$

(408,803

)

Total comprehensive income (loss)

 

$

(430,545

)

$

22,246

 

$

(408,299

)

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

 

 

$

0.32

 

Undistributed

 

(4.94

)

0.24

 

(4.70

)

 

 

$

(4.62

)

$

0.24

 

$

(4.38

)

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.32

 

$

 

 

$

0.32

 

Undistributed

 

(4.94

)

0.24

 

(4.70

)

 

 

$

(4.62

)

$

0.24

 

$

(4.38

)

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2015

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Impairment of oil and gas properties

 

$

3,716,883

 

$

316,412

 

$

4,033,295

 

Depreciation, depletion and amortization

 

$

778,923

 

$

(47,463

)

$

731,460

 

Total operating expenses

 

$

5,193,422

 

$

268,949

 

$

5,462,371

 

Operating income (loss)

 

$

(3,740,803

)

$

(268,949

)

$

(4,009,752

)

Income (loss) before income tax

 

$

(3,782,384

)

$

(268,949

)

$

(4,051,333

)

Income tax expense (benefit)

 

$

(1,373,436

)

$

(98,293

)

$

(1,471,729

)

Net income (loss)

 

$

(2,408,948

)

$

(170,656

)

$

(2,579,604

)

Total comprehensive income (loss)

 

$

(2,409,609

)

$

(170,656

)

$

(2,580,265

)

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

(26.56

)

(1.83

)

(28.39

)

 

 

$

(25.92

)

$

(1.83

)

$

(27.75

)

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

(26.56

)

(1.83

)

(28.39

)

 

 

$

(25.92

)

$

(1.83

)

$

(27.75

)

 

 

Consolidated Statement of Operations and Comprehensive
Income (Loss) for the Year Ended
December 31, 2014

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Depreciation, depletion and amortization

 

$

806,021

 

$

(30,444

)

$

775,577

 

Total operating expenses

 

$

1,610,242

 

$

(30,444

)

$

1,579,798

 

Operating income (loss)

 

$

813,934

 

$

30,444

 

$

844,378

 

Income (loss) before income tax

 

$

805,901

 

$

30,444

 

$

836,345

 

Income tax expense (benefit)

 

$

298,697

 

$

11,150

 

$

309,847

 

Net income (loss)

 

$

507,204

 

$

19,294

 

$

526,498

 

Total comprehensive income (loss)

 

$

507,117

 

$

19,294

 

$

526,411

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

5.15

 

0.22

 

5.37

 

 

 

$

5.79

 

$

0.22

 

$

6.01

 

Diluted

 

 

 

 

 

 

 

Distributed

 

$

0.64

 

$

 

 

$

0.64

 

Undistributed

 

5.14

 

0.22

 

5.36

 

 

 

$

5.78

 

$

0.22

 

$

6.00

 

2. CAPITAL STOCK

Authorized capital stock consists of 200 million shares of common stock and 15 million shares of preferred stock. At December 31, 2016,2018, there were 95.8 million shares of common stock and no shares of preferred stock outstanding. See our Consolidated Statements of Stockholders’ Equity for detailed capital stock activity.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In May 2015, we completed an underwritten public offering of 6,900,000 shares of common stock, which included 900,000 shares of common stock issued pursuant to an overallotment option to purchase additional shares granted to the underwriters.  The stock was sold to the public at $109.00 per share, with a par value of $0.01, and we received net proceeds of approximately $730 million from the sale of these shares of common stock, after deducting underwriting fees.


Dividends

A cash dividend has been paid to stockholders in every quarter since the first quarter of 2006. A dividend of $0.18 per share was declared in both the third and fourth quarters of 2018 while a dividend of $0.16 per share was declared in the first and second quarters of 2018. In Februaryeach quarter of 2017 and 2016 the quarterly dividend was decreased toan $0.08 per share from $0.16 per share.dividend was declared. We typically declare dividends in one quarter and pay them in the next quarter. At December 31, 2018, we had dividends payable of $17.3 million that was included in “Accrued liabilities — other”. Dividends declared are recorded as a reduction of retained earnings to the extent retained earnings are available at the close of the period prior to the date of the declared dividend. Dividends in excess of retained earnings are recorded as a reduction of additional paid-in capital. During 2018, the dividend declared during the first quarter was recorded as a reduction of additional paid-in capital, while the remaining three dividends declared were recorded as a reduction of retained earnings. All dividends declared during 2017 and 2016 were recorded as a reduction of additional paid-in capital. Nonforfeitable dividends paid on stock awards that subsequently forfeit are reclassified out of retained earnings or additional paid-in capital, as applicable, to compensation expense in the period in which the forfeitures occur. Future dividend payments will depend on our level of earnings, financial requirements, and other factors considered relevant by theour Board of Directors.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Dividends declared from Retained earnings (in millions)

 

$

7.5

 

$

59.3

 

$

55.7

 

Dividends declared from Paid-in capital (in millions)

 

$

22.8

 

$

—

 

$

—

 

Dividends per share

 

$

0.32

 

$

0.64

 

$

0.64

 

3. LONG-TERM DEBT

A summary of our

Long-term debt is as follows:

 

 

December 31, 2016

 

December 31, 2015

 

 

 

 

 

Unamortized Debt

 

Long-term

 

 

 

Unamortized Debt

 

Long-term

 

(in thousands)

 

Principal

 

Issuance Costs

 

Debt, net

 

Principal

 

Issuance Costs

 

Debt, net

 

5.875% Senior Notes

 

$

750,000

 

$

(5,691

)

$

744,309

 

$

750,000

 

$

(6,978

)

$

743,022

 

4.375% Senior Notes

 

750,000

 

(6,370

)

743,630

 

750,000

 

(7,402

)

742,598

 

Total long-term debt

 

$

1,500,000

 

$

(12,061

)

$

1,487,939

 

$

1,500,000

 

$

(14,380

)

$

1,485,620

 

Atat December 31, 20162018 and 2015, we had no bank debt outstanding.  All2017 consisted of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest.following:

  December 31, 2018 December 31, 2017
(in thousands) Principal 
Unamortized Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
 Principal 
Unamortized Debt
Issuance Costs and Discount (1)
 
Long-term
Debt, net
4.375% Senior Notes $750,000
 $(4,439) $745,561
 $750,000
 $(5,383) $744,617
3.90% Senior Notes 750,000
 (7,007) 742,993
 750,000
 (7,697) 742,303
Total long-term debt $1,500,000
 $(11,446) $1,488,554
 $1,500,000
 $(13,080) $1,486,920

(1)At December 31, 2018, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.4 million and $1.6 million, respectively.  At December 31, 2017, the unamortized debt issuance costs and discount related to the 3.90% notes were $5.9 million and $1.8 million, respectively. The 4.375% notes were issued at par.

Bank Debt

In October 2015, we entered into a newCredit Agreement for a senior unsecured revolving credit facility (Credit Facility)(“Credit Facility”) with an aggregate commitment of $1.0 billion, which matures October 16, 2020.  The Credit Facility has aggregate commitments of $1.0 billion, with an option to increase aggregate commitments to $1.25 billion at any time. There is no borrowing base subject to the discretion of the lenders based on the value of our proved reserves under the Credit Facility. As of

73
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


December 31, 2016,2018, we had $2.5 million in letters of creditno bank borrowings outstanding under the Credit Facility, but did have letters of credit of $2.5 million outstanding, leaving an unused borrowing availability of $997.5 million.

At our option, borrowings under the Credit Facility may bear interest at either (a) LIBOR plus 1.125 —- 2.0% based on the credit rating for our senior unsecured long-term debt, or (b) a base rate (as defined in the credit agreement) plus 0.125 —- 1.0%, based on the credit rating for our senior unsecured long-term debt. Unused borrowings are subject to a commitment fee of 0.125 —- 0.35%, based on the credit rating for our senior unsecured long-term debt.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Credit Facility contains representations, warranties, covenants, and events of default that are customary for investment grade, senior unsecured bank credit agreements, including a financial covenant for the maintenance of a defined total debt-to-capital ratio of no greater than 65%. As of December 31, 2016,2018, we were in compliance with all of the financial and non-financial covenants.


At December 31, 20162018 and 2015,2017, we had $4.5$2.2 million and $5.7$3.4 million, respectively, of unamortized debt issuance costs associated with our Credit Facility which were recorded as deferred assets and included in Other assets, net“Other assets” in our balance sheets. The costs are being amortized to interest expense ratably over the life of the Credit Facility.


Subsequent Event

On February 5, 2019, we entered into an Amended and Restated Credit Agreement. Among other things, the amended and restated credit facility increases the aggregate commitment to $1.25 billion with an option to increase the commitment to $1.5 billion, and extends the maturity date to February 5, 2024.

Senior Notes

On April 10, 2017, we completed a cash tender offer to purchase any of our 5.875% notes for cash consideration of $1,031.67 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date, with $253.5 million aggregate principal amount of the notes validly tendered.  We settled these tendered notes for $268.1 million, including accrued interest.  On May 12, 2017, we completed a redemption of the 5.875% notes remaining outstanding for $1,029.38 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the redemption date, settling the notes for $512.0 million, including accrued interest.  We recognized a loss on early extinguishment of debt related to these transactions of $28.2 million, composed primarily of tender and redemption premiums of $22.6 million and the write-off of $5.3 million of unamortized debt issuance costs.  The original maturity date of the 5.875% notes was May 1, 2022.
On April 10, 2017, we issued $750 million aggregate principal amount of 3.90% senior unsecured notes due May 15, 2027 at 99.748% of par to yield 3.93% per annum.  We received $741.8 million in net cash proceeds, after deducting underwriters’ fees, discount, and debt issuance costs.  The notes bear an annual interest rate of 3.90% and interest is payable semiannually on May 15 and November 15, with the first payment occurring November 15, 2017.  Along with cash on hand, we used the proceeds to fund the settlement of the tendered and redeemed 5.875% notes. 
In June 2014, we issued $750 million aggregate principal amount of 4.375% senior unsecured notes at par. These notes are due June 1, 2024 and received net proceeds of $740.9 million, after deducting offering discountsinterest is payable semiannually on June 1 and costs.  The net proceeds were used to pay outstanding bank debt and for general corporate purposes.  The effective interest rate on the notes, including the debt issuance costs, is 4.50%.

In April 2012, we issued $750 million of 5.875% senior notes due 2022 and received net proceeds of $737.0 million, after deducting underwriting discounts and offering costs.  We used a portion of the net proceeds to retire our 7.125% senior notes and the remaining proceeds were used to pay outstanding bank debt and for general corporate purposes.  The effective interest rate on the notes, including the debt issuance costs, is 6.04%.  These senior notes are callable by us beginning May 1, 2017 at a price of 102.938% of face value declining to 100% of face value on May 1, 2020 and thereafter.

December 1.  

Each of our outstanding senior unsecured notes is governed by an indenture containing certain covenants, events of default, and other restrictive provisions with which we were in compliance as of December 31, 2016.  Interest2018. The effective interest rate on eachthe 4.375% notes and the 3.90% notes, including the amortization of the seniordebt issuance costs and discount, as applicable, is 4.50% and 4.01%, respectively. At December 31, 2018, we had accrued interest related to our notes is payable semi-annually.

of $6.4 million that was included in “Accrued liabilities — other”.


74
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4. DERIVATIVE INSTRUMENTS/HEDGING

INSTRUMENTS

We periodically enter intouse derivative instruments to mitigate a portion of our potential exposure to a declinevolatility in commodity prices and the corresponding negative impact on cash flow available for reinvestment.prices.  While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenuescash flow from favorable price changes.  Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.  We may hedge up to 50% of our oil and natural gas production on a forward five quarter basis.

The following tables summarize our derivative contracts aspositions from current levels. 

As of December 31, 2016:

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

Oil Collars:

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

WTI (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbls)

 

1,800,000

 

1,820,000

 

1,472,000

 

1,012,000

 

6,104,000

 

Wtd Avg Price - Floor

 

$

43.08

 

$

43.08

 

$

45.09

 

$

46.27

 

$

44.09

 

Wtd Avg Price - Ceiling

 

$

52.90

 

$

52.90

 

$

55.50

 

$

56.98

 

$

54.20

 

 

 

 

 

 

 

 

 

 

 

 

 

2018:

 

 

 

 

 

 

 

 

 

 

 

WTI (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (Bbls)

 

540,000

 

—

 

—

 

—

 

540,000

 

Wtd Avg Price - Floor

 

$

47.33

 

$

—

 

$

—

 

$

—

 

$

47.33

 

Wtd Avg Price - Ceiling

 

$

59.11

 

$

—

 

$

—

 

$

—

 

$

59.11

 

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

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

First

 

Second

 

Third

 

Fourth

 

 

 

 

 

Quarter

 

Quarter

 

Quarter

 

Quarter

 

Total

 

Gas Collars:

 

 

 

 

 

 

 

 

 

 

 

2017:

 

 

 

 

 

 

 

 

 

 

 

PEPL (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

9,900,000

 

10,010,000

 

8,280,000

 

5,520,000

 

33,710,000

 

Wtd Avg Price - Floor

 

$

2.52

 

$

2.52

 

$

2.61

 

$

2.79

 

$

2.59

 

Wtd Avg Price - Ceiling

 

$

3.04

 

$

3.04

 

$

3.12

 

$

3.22

 

$

3.09

 

Perm EP (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

8,100,000

 

8,190,000

 

5,520,000

 

3,680,000

 

25,490,000

 

Wtd Avg Price - Floor

 

$

2.59

 

$

2.59

 

$

2.68

 

$

2.86

 

$

2.65

 

Wtd Avg Price - Ceiling

 

$

3.10

 

$

3.10

 

$

3.16

 

$

3.28

 

$

3.14

 

2018:

 

 

 

 

 

 

 

 

 

 

 

PEPL (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

2,700,000

 

—

 

—

 

—

 

2,700,000

 

Wtd Avg Price - Floor

 

$

2.90

 

$

—

 

$

—

 

$

—

 

$

2.90

 

Wtd Avg Price - Ceiling

 

$

3.32

 

$

—

 

$

—

 

$

—

 

$

3.32

 

Perm EP (1)

 

 

 

 

 

 

 

 

 

 

 

Volume (MMBtu)

 

1,800,000

 

—

 

—

 

—

 

1,800,000

 

Wtd Avg Price - Floor

 

$

3.00

 

$

—

 

$

—

 

$

—

 

$

3.00

 

Wtd Avg Price - Ceiling

 

$

3.41

 

$

—

 

$

—

 

$

—

 

$

3.41

 

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

2018, we have entered into oil and gas collars and oil basis swaps. Under a collar agreement,our collars, we receive the difference between the published index price and a floor price if the index price is below the floor. Wefloor price or 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 the ceiling prices. By using a collar, we have fixed the minimum and maximum prices we can receive on the underlying production. Our basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, we have fixed the differential between the published index price and certain of our physical pricing points. For our Permian oil production, the basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Midland price. For our Permian and Mid-Continent gas production, the contract prices in our collars are consistent with the index prices used to sell our production. The following tables summarize our outstanding derivative contracts as of December 31, 2018:

Oil Collars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2019:  
  
  
  
  
WTI (1)
  
  
  
  
  
Volume (Bbls) 2,790,000
 2,821,000
 2,208,000
 1,472,000
 9,291,000
Weighted Avg Price - Floor $53.94
 $53.94
 $55.67
 $58.50
 $55.07
Weighted Avg Price - Ceiling $66.88
 $66.88
 $70.03
 $71.94
 $68.43
           
2020:  
  
  
  
  
WTI (1)
  
  
  
  
  
Volume (Bbls) 728,000
 —
 —
 —
 728,000
Weighted Avg Price - Floor $60.00
 $—
 $—
 $—
 $60.00
Weighted Avg Price - Ceiling $75.85
 $—
 $—
 $—
 $75.85

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

75
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Gas Collars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2019:  
  
  
  
  
PEPL (1)
  
  
  
  
  
Volume (MMBtu) 10,800,000
 10,920,000
 8,280,000
 5,520,000
 35,520,000
Weighted Avg Price - Floor $2.05
 $2.05
 $1.93
 $1.93
 $2.00
Weighted Avg Price - Ceiling $2.42
 $2.42
 $2.34
 $2.42
 $2.40
Perm EP (2)
  
  
  
  
  
Volume (MMBtu) 7,200,000
 7,280,000
 5,520,000
 2,760,000
 22,760,000
Weighted Avg Price - Floor $1.69
 $1.69
 $1.48
 $1.37
 $1.60
Weighted Avg Price - Ceiling $1.92
 $1.92
 $1.74
 $1.60
 $1.84
Waha (3)
          
Volume (MMBtu) 2,700,000
 2,730,000
 2,760,000
 2,760,000
 10,950,000
Weighted Avg Price - Floor $1.38
 $1.38
 $1.38
 $1.38
 $1.38
Weighted Avg Price - Ceiling $1.67
 $1.67
 $1.67
 $1.67
 $1.67
2020:  
  
  
  
  
PEPL (1)
  
  
  
  
  
Volume (MMBtu) 2,730,000
 —
 —
 —
 2,730,000
Weighted Avg Price - Floor $1.97
 $—
 $—
 $—
 $1.97
Weighted Avg Price - Ceiling $2.51
 $—
 $—
 $—
 $2.51
Perm EP (2)
  
  
  
  
  
Volume (MMBtu) 910,000
 —
 —
 —
 910,000
Weighted Avg Price - Floor $1.40
 $—
 $—
 $—
 $1.40
Weighted Avg Price - Ceiling $1.70
 $—
 $—
 $—
 $1.70
Waha (3)
          
Volume (MMBtu) 1,820,000
 —
 —
 —
 1,820,000
Weighted Avg Price - Floor $1.40
 $—
 $—
 $—
 $1.40
Weighted Avg Price - Ceiling $1.73
 $—
 $—
 $—
 $1.73

(1)The index price for these collars is Panhandle Eastern Pipe Line, Tex/OK Mid-Continent Index (“PEPL”) as quoted in Platt’s Inside FERC.  
(2)The index price for these collars is El Paso Natural Gas Company, Permian Basin Index (“Perm EP”) as quoted in Platt’s Inside FERC.
(3)The index price for these collars is Waha West Texas Natural Gas Index (“Waha”) as quoted in Platt’s Inside FERC.
Oil Basis Swaps 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2019:          
WTI Midland (1)
          
Volume (Bbls) 2,610,000
 2,639,000
 2,208,000
 1,472,000
 8,929,000
Weighted Avg Differential (2) $(5.46) $(5.46) $(6.50) $(7.79) $(6.10)
2020:          
WTI Midland (1)
          
Volume (Bbls) 637,000
 637,000
 —
 —
 1,274,000
Weighted Avg Differential (2) $(0.40) $(0.40) $—
 $—
 $(0.40)

(1)The index price we pay under these basis swaps is WTI Midland as quoted by Argus Americas Crude.
(2)The index price we receive under these basis swaps is WTI as quoted on the NYMEX less the weighted average differential shown in the table.

76
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following tables summarize our derivative contracts entered into subsequent to December 31, 2018 through February 15, 2019:
Oil Collars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2019:          
WTI (1)          
Volume (Bbls) 62,000
 182,000
 184,000
 184,000
 612,000
Weighted Avg Price - Floor $50.00
 $50.00
 $50.00
 $50.00
 $50.00
Weighted Avg Price - Ceiling $62.60
 $62.60
 $62.60
 $62.60
 $62.60
2020:          
WTI (1)          
Volume (Bbls) 182,000
 182,000
 —
 —
 364,000
Weighted Avg Price - Floor $50.00
 $50.00
 $—
 $—
 $50.00
Weighted Avg Price - Ceiling $62.60
 $62.60
 $—
 $—
 $62.60

(1)The index price for these collars is WTI as quoted on the NYMEX.
Gas Collars 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
2019:          
PEPL (1)
          
Volume (MMBtu) 1,770,000
 2,730,000
 2,760,000
 2,760,000
 10,020,000
Weighted Avg Price - Floor $1.95
 $1.95
 $1.95
 $1.95
 $1.95
Weighted Avg Price - Ceiling $2.26
 $2.26
 $2.26
 $2.26
 $2.26
Perm EP (2)
          
Volume (MMBtu) 590,000
 910,000
 920,000
 920,000
 3,340,000
Weighted Avg Price - Floor $1.50
 $1.50
 $1.50
 $1.50
 $1.50
Weighted Avg Price - Ceiling $2.13
 $2.13
 $2.13
 $2.13
 $2.13
Waha (3)
          
Volume (MMBtu) 590,000
 910,000
 920,000
 920,000
 3,340,000
Weighted Avg Price - Floor $1.50
 $1.50
 $1.50
 $1.50
 $1.50
Weighted Avg Price - Ceiling $1.90
 $1.90
 $1.90
 $1.90
 $1.90
2020:          
PEPL (1)
          
Volume (MMBtu) 2,730,000
 2,730,000
 —
 —
 5,460,000
Weighted Avg Price - Floor $1.95
 $1.95
 $—
 $—
 $1.95
Weighted Avg Price - Ceiling $2.26
 $2.26
 $—
 $—
 $2.26
Perm EP (2)
          
Volume (MMBtu) 910,000
 910,000
 —
 —
 1,820,000
Weighted Avg Price - Floor $1.50
 $1.50
 $—
 $—
 $1.50
Weighted Avg Price - Ceiling $2.13
 $2.13
 $—
 $—
 $2.13
Waha (3)
          
Volume (MMBtu) 910,000
 910,000
 —
 —
 1,820,000
Weighted Avg Price - Floor $1.50
 $1.50
 $—
 $—
 $1.50
Weighted Avg Price - Ceiling $1.90
 $1.90
 $—
 $—
 $1.90

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

77
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Derivative Gains and Losses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments.  We have elected not to account fordesignate our derivatives as cash flow hedges. Therefore,hedging instruments for accounting purposes and, therefore, we recognize settlements anddo not apply hedge accounting treatment to our derivative instruments.  Consequently, changes in the fair value of assetsour derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or liabilities relating to our openloss on derivative contracts in earnings.instruments.  Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows.

The following table presents the components of (Gain) loss on derivative instruments, net (gains) and losses from settlements and changes in fair value of our derivative contracts, and the (gains) losses from cash settlements duringfor the periods shown below.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

(Gain) loss on derivative instruments, net:

 

 

 

 

 

 

 

Natural gas contracts

 

$

20,995

 

$

(4,472

)

$

6,751

 

Oil contracts

 

34,754

 

(6,774

)

(10,512

)

(Gain) loss on derivative instruments, net

 

$

55,749

 

$

(11,246

)

$

(3,761

)

Settlement (gains) losses:

 

 

 

 

 

 

 

Natural gas contracts

 

$

(6,467

)

$

—

 

$

4,287

 

Oil contracts

 

(970

)

—

 

(11,928

)

Settlement (gains) losses

 

$

(7,437

)

$

—

 

$

(7,641

)

indicated.

  Years Ended December 31,
(in thousands) 2018 2017 2016
Decrease (increase) in fair value of derivative instruments, net:  
  
  
Gas contracts $15,742
 $(40,226) $27,462
Oil contracts (126,130) 17,383
 35,724

 (110,388) (22,843) 63,186
Cash (receipts) payments on derivative instruments, net:  
  
  
Gas contracts (13,794) (4,557) (6,467)
Oil contracts 38,223
 6,190
 (970)

 24,429
 1,633
 (7,437)
(Gain) loss on derivative instruments, net $(85,959) $(21,210) $55,749
Derivative Fair Value
Our derivative contracts are carried at their fair value on our balance sheet using Level 2 inputs and are subject to enforceable master netting arrangements, which allow us to offset recognized asset and liability fair value amounts on contracts with the same counterparty.  Our accounting policy is to not offset asset and liability positions in our accompanying balance sheets.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table presentstables present the amounts and classifications of our derivative assets and liabilities as of December 31, 20162018 and 2015,2017, as well as the potential effect of netting arrangements on contracts with the same counterparty.

December 31, 2016:

 

 

 

 

 

 

 

(in thousands)

 

Balance Sheet Location

 

Asset

 

Liability

 

Oil contracts

 

Current liabilities — Derivative instruments

 

$

—

 

$

27,892

 

Natural gas contracts

 

Current liabilities — Derivative instruments

 

—

 

21,478

 

Oil contracts

 

Non-current liabilities — Derivative instruments

 

—

 

1,059

 

Natural gas contracts

 

Non-current liabilities — Derivative instruments

 

—

 

1,511

 

Total gross amounts presented in accompanying balance sheet

 

—

 

51,940

 

Less: gross amounts not offset in the accompanying balance sheet

 

—

 

—

 

Net amount:

 

 

 

$

—

 

$

51,940

 

December 31, 2015:

 

 

 

 

 

 

 

(in thousands)

 

Balance Sheet Location

 

Asset

 

Liability

 

Oil contracts

 

Current assets — Derivative instruments

 

$

6,774

 

$

—

 

Natural gas contracts

 

Current assets — Derivative instruments

 

3,971

 

—

 

Natural gas contracts

 

Non-current assets — Derivative instruments

 

501

 

—

 

Total gross amounts presented in accompanying balance sheet

 

11,246

 

—

 

Less: gross amounts not offset in the accompanying balance sheet

 

—

 

—

 

Net amount:

 

 

 

$

11,246

 

$

—

 

our recognized derivative asset and liability amounts.

    December 31, 2018
(in thousands) Balance Sheet Location Asset Liability
Oil contracts Current assets — Derivative instruments $94,240
 $—
Gas contracts Current assets — Derivative instruments 7,699
 —
Oil contracts Non-current assets — Derivative instruments 9,246
 —
Oil contracts Current liabilities — Derivative instruments —
 23,378
Gas contracts Current liabilities — Derivative instruments —
 4,249
Oil contracts Non-current liabilities — Derivative instruments —
 311
Gas contracts Non-current liabilities — Derivative instruments —
 1,956
Total gross amounts presented in the balance sheet 111,185
 29,894
Less: gross amounts not offset in the balance sheet (29,894) (29,894)
Net amount $81,291
 $—

78
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


    December 31, 2017
(in thousands) Balance Sheet Location Asset Liability
Gas contracts Current assets — Derivative instruments $15,151
 $—
Gas contracts Non-current assets — Derivative instruments 2,086
 —
Oil contracts Current liabilities — Derivative instruments —
 42,066
Oil contracts Non-current liabilities — Derivative instruments —
 4,268
Total gross amounts presented in the balance sheet 17,237
 46,334
Less: gross amounts not offset in the balance sheet (17,237) (17,237)
Net amount $—
 $29,097
We are exposed to financial risks associated with our derivative contracts from non-performance by our counterparties.  We mitigate our exposure to any single counterparty by contracting with a number of financial institutions, each of which have a high credit rating and is a member of our bank credit facility.  Our member banks do not require us to post collateral for our hedgederivative liability positions. Because some of the member banks have discontinued hedging activities, inpositions, nor do we require our counterparties to post collateral for our benefit.  In the future we may hedgeenter into derivative instruments with counterparties outside our bank group to obtain competitive terms and to spread counterparty risk.

5. 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 table provides fair value measurement information for certain assets and liabilities as of December 31, 20162018 and 2015.

 

 

December 31, 2016

 

December 31, 2015

 

 

 

Book

 

Fair

 

Book

 

Fair

 

(in thousands)

 

Value

 

Value

 

Value

 

Value

 

Financial Assets (Liabilities):

 

 

 

 

 

 

 

 

 

5.875% Notes due 2022

 

$

(750,000

)

$

(782,835

)

$

(750,000

)

$

(723,750

)

4.375% Notes due 2024

 

$

(750,000

)

$

(779,453

)

$

(750,000

)

$

(683,318

)

Derivative instruments — assets

 

$

—

 

$

—

 

$

11,246

 

$

11,246

 

Derivative instruments — liabilities

 

$

(51,940

)

$

(51,940

)

$

—

 

$

—

 

2017.


  December 31, 2018 December 31, 2017
(in thousands) Book Value Fair Value Book Value Fair Value
Financial Assets (Liabilities):  
  
  
  
4.375% Notes due 2024 $(750,000) $(744,578) $(750,000) $(797,010)
3.90% Notes due 2027 $(750,000) $(701,273) $(750,000) $(767,813)
Derivative instruments — assets $111,185
 $111,185
 $17,237
 $17,237
Derivative instruments — liabilities $(29,894) $(29,894) $(46,334) $(46,334)
Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability.  The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt (Level 1)

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

Derivative Instruments (Level 2)

The fair value of our derivative instruments (Level 2) was estimated using option pricing models.  These models use certain variables including forward price and volatility curves and the strike prices for the instruments.  The fair value estimates are adjusted relative to non-performance risk as appropriate.  See Note 4 for further information on the fair value of our derivative instruments.

Other Financial Instruments

The carrying amounts of our cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities. Included in “Accrued liabilities — other” at December 31, 20162018 are: (i) accrued operating expenses (e.g. production, transportation, and 2015, respectively, are 1) liabilitiesgathering expenses) of approximately $19.3$69.1 million, (ii) accrued general and administrative, primarily payroll-related, costs of approximately $47.4 million, and $23.1(iii) an accrual of approximately $35.8 million representing the amount by which checks issued, but not yet presented to our banks, exceeded balances inapplicable

79
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


bank accounts. Included in applicable bank accounts; 2) accrued payroll related costs of $43.5 million and $21.5 million; and 3)“Accrued liabilities — other” at December 31, 2017 are: (i) accrued operating expenses (e.g. production, transportation, and gathering expenses) of $53.9approximately $61.3 million and $60.4(ii) accrued general and administrative, primarily payroll-related, costs of approximately $54.6 million.

Our

Most of our accounts receivable balances are primarilyuncollateralized and result from either purchaserstransactions with other companies in the oil and gas industry.  Concentration of our oil, gas, and NGL production (customers) or from exploration and production companies which own interests in properties we operate.  This industry concentration has the potential tocustomers may impact our overall exposure to credit risk either positively or negatively, because our customers and joint working interest owners may be similarly affected by changes in industry conditions.

economic or other conditions within the industry.

We conduct credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary.

We routinely assess the recoverability of all material accounts receivable to determine their collectability. We accrue a reserve to the allowance for doubtful accounts when it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. At December 31, 20162018 and 2015,2017, the allowance for doubtful accounts totaled $1.6$2.7 million and $1.8$2.2 million, respectively.

Major Customers

Our major


In each of the years ended December 31, 2018 and 2017, we made sales to two customers that each amounted to 10% or more of our consolidated revenues for the respective year. Sales to those two customers accounted for 23% and 21%, respectively, of our consolidated revenues in 2018 and 21% and 13%, respectively, of our consolidated revenues in 2017. In 2016, we made sales to one customer during 2016 was Sunoco Logistics Partners L.P. (Sunoco), whichthat amounted to 10% or more of our consolidated revenues that year. Sales to that customer accounted for 20% of our consolidated revenues.  Sunoco and Enterprise Products Partners L.P. (Enterprise) wererevenues in 2016.
If any one of our major customers in 2015, accounting for 21% and 17%, respectively, of our consolidated revenues that year.  During 2014, Sunoco and Enterprise each accounted for 19% of our consolidated revenues and Oneok Partners, L.P. accounted for 10% of our consolidated revenues.

If Sunoco was to stop purchasing our production, we believe there are a number of other purchasers to whom we could sell our production with some delay. If multiple significant customers were to discontinue purchasing our product,production, we believe there would be challenges initially, but ample markets to handle the disruption.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. STOCK-BASED AND OTHER COMPENSATION

We have recognized non-cash stock-based compensation cost as shown below.  Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Restricted stock awards

 

 

 

 

 

 

 

Performance stock awards

 

$

24,183

 

$

18,991

 

$

12,141

 

Service-based stock awards

 

18,391

 

14,547

 

13,607

 

 

 

42,574

 

33,538

 

25,748

 

Stock option awards

 

2,565

 

2,803

 

3,057

 

 

 

45,139

 

36,341

 

28,805

 

Less amounts capitalized to oil and gas properties

 

(20,616

)

(16,782

)

(13,804

)

Compensation expense

 

$

24,523

 

$

19,559

 

$

15,001

 

The increase in 2016 stock compensation is primarily related to performance awards granted in December 2015, a portion of which were amortized during 2016, forfeiture rate adjustments on the service-based stock awards, and the acceleration of expense on a portion of service-based awards for employees who participated in a voluntary early retirement incentive program.

Equity Incentive Plan

Our 2014 Equity Incentive Plan (the 2014 Plan)“2014 Plan”) was approved by stockholders in May 2014 and our previous plan was terminated at that time. Outstanding awards under the previous plan were not impacted. A total of 6.6 million shares of common stock may be issued under the 2014 Plan, including shares available from the previous plan. 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.



80
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Stock-based Compensation Cost

We have recognized non-cash stock-based compensation cost as shown below. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts.
  Years Ended December 31,
(in thousands) 2018 2017 2016
Restricted stock awards:  
  
  
Performance stock awards $23,083
 $26,020
 $24,183
Service-based stock awards 20,385
 19,746
 18,391
  43,468
 45,766
 42,574
Stock option awards 2,456
 2,599
 2,565
Total stock compensation cost 45,924
 48,365
 45,139
Less amounts capitalized to oil and gas properties (23,029) (22,109) (20,616)
Stock compensation expense $22,895
 $26,256
 $24,523
Periodic stock compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, employee forfeitures, and the timing of the awards.  The decrease in total stock compensation cost in 2018 as compared to 2017 is primarily due to performance stock award forfeitures during the second quarter 2018. Our accounting policy is to account for forfeitures in compensation cost when they occur.
We adopted Accounting Standards Update 2016-09, Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) on January 1, 2017.  The amendments within ASU 2016-09 related to the timing of when excess tax benefits and tax benefits on dividends on nonvested equity shares are recognized and accounting for forfeitures were adopted using a modified retrospective method.  In accordance with this method, we recorded a cumulative-effect adjustment that increased beginning deferred income tax assets by $33.1 million, reduced beginning accumulated deficit by $28.7 million, and increased beginning additional paid-in capital by $4.4 million.  The amendments within ASU 2016-09 related to the presentation in the statement of cash flows of excess tax benefits and cash outflows attributable to the payment of employee tax withholdings on the net settlement of equity-classified awards were adopted using a retrospective method.  In accordance with this method, we adjusted the statement of cash flows for the year ended December 31, 2016 by increasing both net cash provided by operating activities and net cash used by financing activities by $26.6 million for the payment of employee tax withholdings on the net settlement of equity-classified awards. There were no cash flows related to excess tax benefits during the year ended December 31, 2016.
Restricted Stock

The following table provides information about restricted stock awards granted during the last three years.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

 

 

 

 

Weighted

 

 

 

Weighted

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

Average

 

 

 

Average

 

 

 

Number

 

Grant-Date

 

Number

 

Grant-Date

 

Number

 

Grant-Date

 

 

 

of Shares

 

Fair Value

 

of Shares

 

Fair Value

 

of Shares

 

Fair Value

 

Performance stock awards

 

269,915

 

$

117.63

 

263,939

 

$

87.12

 

316,441

 

$

83.22

 

Service-based stock awards

 

208,724

 

$

114.61

 

207,180

 

$

114.80

 

170,402

 

$

136.72

 

Total restricted stock awards

 

478,639

 

$

116.31

 

471,119

 

$

99.29

 

486,843

 

$

101.95

 

 Years Ended December 31,
 2018 2017 2016
 
Number
of Shares
 
Weighted
Average
Grant Date
Fair Value
 
Number
of Shares
 
Weighted
Average
Grant Date
Fair Value
 
Number
of Shares
 
Weighted
Average
Grant Date
Fair Value
Performance stock awards123,533
 $90.26
 300,525
 $89.46
 269,915
 $117.63
Service-based stock awards469,438
 $81.29
 251,312
 $94.04
 208,724
 $114.61
Total restricted stock awards592,971
 $83.16
 551,837
 $91.55
 478,639
 $116.31
Performance stock awards were granted to eligible executives and are subject to service and market condition-based vesting determined by our stock price performance relative to a defined peer group’s stock price performance. AfterFor awards granted prior to 2018, after three years of continued service, an executive will be entitled to vest in 50% to

81
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


100% of the award. For awards granted in 2018, after three years of continued service, an executive will be entitled to vest in 0% to 200% 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 threeranging from one to five years.

The majority of our service-based stock awards cliff vest five years from the grant date.

Compensation cost for the performance stock awards is based on the grant-dategrant date fair value of the award utilizing a Monte Carlo simulation model. Compensation cost for the service-based vesting restricted sharesstock awards is based upon the grant-dategrant date market value of the award. Such costs are recognized ratably over the applicable vesting period.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information on restricted stock activity during the year.
 Service-based 
Performance
(subject to market conditions)
 
Number of
Shares
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Shares
 
Weighted
Average
Grant Date
Fair Value
Outstanding as of January 1, 2018910,251
 $103.98
 834,379
 $97.83
Vested(213,983) $80.17
 (170,045) $87.12
Granted469,438
 $81.29
 123,533
 $90.26
Canceled (1)—
 $—
 (75,533) $87.13
Forfeited(29,824) $102.35
 (62,238) $98.01
Outstanding as of December 31, 20181,135,882
 $99.12
 650,096
 $100.42

 

 

 

 

 

 

Performance

 

 

 

Service-based

 

(subject to market conditions)

 

 

 

 

 

Weighted

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

Average

 

 

 

Number of

 

Grant-Date

 

Number of

 

Grant-Date

 

 

 

Shares

 

Fair Value

 

Shares

 

Fair Value

 

Outstanding as of January 1, 2016

 

998,182

 

$

91.37

 

829,808

 

$

82.99

 

Vested

 

(243,313

)

$

92.37

 

(287,108

)

$

81.53

 

Granted

 

208,724

 

$

114.61

 

269,915

 

$

117.63

 

Canceled

 

(28,870

)

$

110.84

 

(3,345

)

$

87.14

 

Outstanding as of December 31, 2016

 

934,723

 

$

96.57

 

809,270

 

$

96.41

 

(1)These performance shares were canceled since the market condition was not satisfied as of the end of the performance period.


The total fairvest date market value of restricted stock that vested was $34.1 million in 2018, $54.4 million in 2017, and $67.9 million in 2016, $52.2 million in 2015, and $34.1 million in 2014.

2016.

Unrecognized compensation cost related to unvested restricted stock at December 31, 20162018 was $96.0$102.3 million. We expect to recognize that cost over a weighted average period of 2.82.9 years.

Restricted Units


As of December 31, 20162018 and 2015,2017, we had 8,838 restricted units outstanding. These 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.

Stock Options

Options that have been granted under the 2014 plan and previous plansoutstanding as of December 31, 2018 expire seven to ten years from the grant date and have service-based vesting scheduleswhereby the awards vest in increments of one-third on each of the first three to five years.anniversary dates of the grant. The exercise price for an option under the 2014 planPlan is the closing price of our common stock as reported by the New York Stock Exchange (NYSE)(“NYSE”) 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 NYSE on the date of grant.

Compensation cost related to stock options is based on the grant-dategrant date fair value of the award and is 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.exercise. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.


82
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following summarizes theinformation regarding options granted, and related information, andincluding the assumptions used to determine the fair value of those options.

 

 

Years Ended December 31,

 

 

 

2016

 

2015

 

2014

 

Options granted

 

89,850

 

69,000

 

82,500

 

Weighted average grant-date fair value

 

$

33.38

 

$

37.56

 

$

41.69

 

Weighted average exercise price

 

$

114.07

 

$

115.28

 

$

139.02

 

Total fair value (in thousands)

 

$

2,999

 

$

2,592

 

$

3,439

 

Expected years until exercise

 

4.0

 

5.0

 

4.0

 

Expected stock volatility

 

36.7

%

36.6

%

36.7

%

Dividend yield

 

0.3

%

0.6

%

0.5

%

Risk-free interest rate

 

0.96

%

1.6

%

1.8

%

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


 Years Ended December 31,
 2018 2017 2016
Options granted92,050
 96,100
 89,850
Weighted average grant date fair value$26.71
 $28.37
 $33.38
Weighted average exercise price$83.28
 $92.37
 $114.07
Total fair value (in thousands)$2,458
 $2,727
 $2,999
Expected years until exercise5.0
 4.5
 4.0
Expected stock volatility34.7% 35.0% 36.7%
Dividend yield0.9% 0.3% 0.3%
Risk-free interest rate2.7% 1.7% 1.0%
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, 2016

 

299,229

 

$

93.76

 

 

 

 

 

Exercised

 

(63,727

)

$

75.37

 

 

 

 

 

Granted

 

89,850

 

$

114.07

 

 

 

 

 

Canceled

 

(1,997

)

$

139.02

 

 

 

 

 

Forfeited

 

(15,545

)

$

123.00

 

 

 

 

 

Outstanding as of December 31, 2016

 

307,810

 

$

101.72

 

4.6 Years

 

$

10,846

 

Exercisable as of December 31, 2016

 

159,449

 

$

86.99

 

3.4 Years

 

$

7,996

 

 Number of Options 
Weighted
Average
Exercise
Price
 
Weighted
Average
Remaining
Term
 
Aggregate
Intrinsic
Value
(in thousands)
Outstanding as of January 1, 2018382,688
 $100.17
    
Exercised(33,233) $67.44
    
Granted92,050
 $83.28
    
Canceled(5,345) $117.27
    
Forfeited(15,828) $95.70
    
Outstanding as of December 31, 2018420,332
 $99.01
 4.2 years $526
Exercisable as of December 31, 2018250,091
 $104.43
 3.1 years $526
The following table provides information regarding options exercised and the grant-dategrant date fair value of options vested.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Number of options exercised

 

63,727

 

141,517

 

211,258

 

Cash received from option exercises

 

$

4,804

 

$

8,451

 

$

11,898

 

Tax benefit from option exercises included in paid-in-capital (1)

 

$

—

 

$

4,442

 

$

—

 

Intrinsic value of options exercised

 

$

2,994

 

$

7,467

 

$

15,384

 

Grant-date fair value of options vested

 

$

2,486

 

$

2,734

 

$

4,419

 

(1)         No tax benefit is recorded until the benefit reduces current taxes payable. However, in 2015 we recognized tax benefit on prior period option exercises.

  Years Ended December 31,
(in thousands) 2018 2017 2016
Cash received from option exercises $2,241
 $394
 $4,804
Intrinsic value of options exercised $1,030
 $257
 $2,994
Grant date fair value of options vested $2,547
 $2,227
 $2,486
The following summary reflects the status of non-vested stock options as of December 31, 20162018 and changes during the year.

 

 

 

 

Weighted

 

Weighted

 

 

 

 

 

Average

 

Average

 

 

 

 

 

Grant-Date

 

Exercise

 

 

 

Options

 

Fair Value

 

Price

 

Non-vested as of January 1, 2016

 

157,041

 

$

34.77

 

$

111.58

 

Vested

 

(82,985

)

$

29.95

 

$

101.46

 

Granted

 

89,850

 

$

33.38

 

$

114.07

 

Forfeited

 

(15,545

)

$

19.70

 

$

123.00

 

Non-vested as of December 31, 2016

 

148,361

 

$

35.58

 

$

117.55

 

 Number of Options 
Weighted
Average
Grant Date
Fair Value
 
Weighted
Average
Exercise
Price
Non-vested as of January 1, 2018172,906
 $31.08
 $102.15
Vested(78,887) $32.28
 $105.37
Granted92,050
 $26.71
 $83.28
Forfeited(15,828) $29.61
 $95.70
Non-vested as of December 31, 2018170,241
 $28.29
 $91.05

83
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


As of December 31, 2016,2018, there was $3.6 million of unrecognized compensation cost related to non-vested stock options. We expect to recognize that cost on a pro rata basis over a weighted average period of 2.01.4 years.

Other Compensation

We maintain and sponsor a contributory 401(k) plan for our employees. Annual matching costsEmployer contributions related to the plan were $13.1 million, $10.4 million, and $6.7 million $6.4 million,for 2018, 2017, and $11.0 million for 2016, 2015,respectively. Included in the 2018 and 2014, respectively.

2017 amounts are accrued employer discretionary contributions. No such employer discretionary contributions occurred in 2016.

84

Table of Contents
CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



7. EARNINGS (LOSS) PER SHARE

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

 

 

Years Ended December 31,

 

(in thousands, except per share data)

 

2016

 

2015

 

2014

 

Basic:

 

 

 

 

 

 

 

Net income (loss)

 

$

(408,803

)

$

(2,579,604

)

$

526,498

 

Participating securities’ share in earnings (1)

 

—

 

—

 

(10,329

)

Net income (loss) applicable to common stockholders

 

$

(408,803

)

$

(2,579,604

)

$

516,169

 

Diluted:

 

 

 

 

 

 

 

Net income (loss)

 

$

(408,803

)

$

(2,579,604

)

$

526,498

 

Participating securities’ share in earnings (1)

 

—

 

—

 

(10,314

)

Net income (loss) applicable to common stockholders

 

$

(408,803

)

$

(2,579,604

)

$

516,184

 

Shares:

 

 

 

 

 

 

 

Basic shares outstanding

 

93,379

 

92,992

 

85,679

 

Dilutive effect of stock options

 

—

 

—

 

131

 

Fully diluted common stock

 

93,379

 

92,992

 

85,810

 

Excluded (2)

 

2,061

 

2,136

 

94

 

Earnings (loss) per share to common stockholders (3):

 

 

 

 

 

 

 

Basic

 

$

(4.38

)

$

(27.75

)

$

6.01

 

Diluted

 

$

(4.38

)

$

(27.75

)

$

6.00

 

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

(2)         Inclusion of certain shares would have an anti-dilutive effect.

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


  Year Ended December 31, 2018
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount
Net income $791,851
  
  
Less: net income attributable to participating securities (11,087)    
Basic earnings per share      
Income available to common stockholders 780,764
 93,793
 $8.32
Effects of dilutive securities      
Options (1) 3
 27
  
Diluted earnings per share      
Income available to common stockholders and assumed conversions $780,767
 93,820
 $8.32
  Year Ended December 31, 2017
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount
Net income $494,329
  
  
Less: net income attributable to participating securities (8,551)    
Basic earnings per share      
Income available to common stockholders 485,778
 93,466
 $5.19
Effects of dilutive securities      
Options (1) 3
 43
  
Diluted earnings per share      
Income available to common stockholders and assumed conversions $485,781
 93,509
 $5.19
  Year Ended December 31, 2016
(in thousands, except per share information) Income (Numerator) Shares (Denominator) Per-Share Amount
Net loss $(408,803)  
  
Less: net loss attributable to participating securities (2) —
    
Basic loss per share      
Loss available to common stockholders (408,803) 93,379
 $(4.38)
Effects of dilutive securities      
Options (1) —
 —
  
Diluted loss per share      
Loss available to common stockholders and assumed conversions $(408,803) 93,379
 $(4.38)

(1)Inclusion of certain shares would have an anti-dilutive effect; therefore, 387.7 thousand, 302.9 thousand, and 2.1 million shares were excluded from the calculations for the years ended December 31, 2018, 2017, and 2016, respectively.
(2)Participating securities do not participate in losses.


85
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


8. ASSET RETIREMENT OBLIGATIONS

The following table reflects the components of the change in the carrying amount of the asset retirement obligation for the years ended December 31, 20162018 and 2015.

(in thousands)

 

2016

 

2015

 

Asset retirement obligation at January 1,

 

$

164,105

 

$

173,008

 

Liabilities incurred

 

3,914

 

4,114

 

Liability settlements and disposals

 

(24,108

)

(25,061

)

Accretion expense

 

7,595

 

7,682

 

Revisions of estimated liabilities

 

3,017

 

4,362

 

Asset retirement obligation at December 31,

 

154,523

 

164,105

 

Less current obligation

 

13,753

 

10,248

 

Long-term asset retirement obligation

 

$

140,770

 

$

153,857

 

2017.


(in thousands) 2018 2017
Asset retirement obligation at January 1, $169,469
 $154,523
Liabilities incurred 9,899
 17,996
Liability settlements and disposals (21,550) (12,947)
Accretion expense 7,318
 7,534
Revisions of estimated liabilities 1,768
 2,363
Asset retirement obligation at December 31, 166,904
 169,469
Less current obligation 14,146
 11,048
Long-term asset retirement obligation $152,758
 $158,421
Liabilities incurred in 2017 includes $10.5 million for the estimated liability to decommission two offshore properties in the Gulf of Mexico in which we were a prior lessee. In January 2018, the Bureau of Safety and Environmental Enforcement (“BSEE”) notified us and other prior lessees that the current lessee of the properties had filed a petition for relief under the bankruptcy code and, as a result, had defaulted on its obligation to decommission the properties. Consequently, BSEE ordered us and other prior lessees to decommission all wells, pipelines, platforms, and other facilities related to these properties. Our estimate of our liability may change as we refine our understanding of the extent of our obligations under the orders from BSEE and obtain additional information on decommissioning costs.
During 20162018 and 2015,2017, the liability settlements and disposals included $14.9$13.7 million and $13.3$0.5 million, respectively, related to properties that were sold.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. INCOME TAXES

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

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Current taxes:

 

 

 

 

 

 

 

Federal expense

 

$

—

 

$

14,417

 

$

—

 

State (benefit) expense

 

(1,115

)

293

 

404

 

 

 

(1,115

)

14,710

 

404

 

Deferred taxes:

 

 

 

 

 

 

 

Federal (benefit) expense

 

(201,529

)

(1,386,086

)

293,385

 

State (benefit) expense

 

(11,757

)

(100,353

)

16,058

 

 

 

(213,286

)

(1,486,439

)

309,443

 

 

 

$

(214,401

)

$

(1,471,729

)

$

309,847

 


  Years Ended December 31,
(in thousands) 2018 2017 2016
Current taxes:  
  
  
Federal benefit $(3,007) $(2,810) $—
State expense (benefit) 383
 (2) (1,115)
  (2,624) (2,812) (1,115)
Deferred taxes:  
  
  
Federal expense (benefit) 211,717
 173,859
 (201,529)
State expense (benefit) 21,563
 16,620
 (11,757)
  233,280
 190,479
 (213,286)
  $230,656
 $187,667
 $(214,401)


86
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Federal income tax expense (benefit) for the years presented differs from the amounts that would be provided by applying the U.S. federal income tax rate, primarily due to the effect of state income taxes, non-deductible expenses, revisions, and revisions.changes in tax laws and tax rates enacted in the period. Reconciliations of the income tax expense (benefit) calculated at the federal statutory rate of 21% for 2018 and 35% for 2017 and 2016 to the total income tax expense (benefit) are as follows:

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Provision at statutory rate

 

$

(218,122

)

$

(1,417,967

)

$

292,721

 

Effect of state taxes

 

(10,237

)

(64,794

)

16,321

 

Revision of previous balances

 

7,181

 

5,997

 

—

 

Other permanent differences

 

5,296

 

5,035

 

805

 

Change in valuation allowance

 

1,481

 

—

 

—

 

Income tax expense (benefit)

 

$

(214,401

)

$

(1,471,729

)

$

309,847

 

  Years Ended December 31,
(in thousands) 2018 2017 2016
Provision at statutory rate $214,726
 $238,699
 $(218,122)
Effect of state taxes 18,795
 10,074
 (10,237)
Revision of previous balances —
 —
 7,181
Tax credits and other permanent differences 1,583
 5,442
 5,296
Change in valuation allowance, net (1,376) 486
 1,481
Stock-based compensation (3,072) (5,888) —
Impact of reduction in federal statutory rate —
 (61,146) —
Income tax expense (benefit) $230,656
 $187,667
 $(214,401)
As a result of the enactment of H.R.1 (Public Law 115-97) on December 22, 2017, the company remeasured the deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the U.S. income tax rate from 35% to 21% for years after 2018. As a result of this remeasurement, we recorded an income tax benefit of $61.1 million and a corresponding $61.1 million decrease in net deferred tax liabilities as of December 31, 2017. We believe the accounting for the effects of H.R.1 recognized in the December 31, 2017 financial statements is materially complete. During 2018, no other adjustments were made. As a result of H.R.1, we expect our effective tax rate in future periods will be lower than in periods prior to enactment. In addition, the limitations on utilization of net operating losses and deductibility of interest and executive compensation may result in the payment of cash taxes earlier than expected.
The components of net deferred taxes are as follows:

 

 

December 31,

 

(in thousands)

 

2016

 

2015

 

Assets:

 

 

 

 

 

Stock compensation and other accrued amounts

 

$

58,306

 

$

32,084

 

Net operating loss carryforward, net of valuation allowance

 

399,912

 

305,506

 

Credit carryforward

 

6,016

 

6,016

 

 

 

464,234

 

343,606

 

Liabilities:

 

 

 

 

 

Property, plant and equipment

 

(408,399

)

(500,768

)

 

 

 

 

 

 

Net deferred tax assets (liabilities)

 

$

55,835 

 

$

(157,162

)


  December 31,
(in thousands) 2018 2017
Assets:  
  
Stock compensation and other accrued amounts $8,229
 $31,044
Net operating loss carryforward, net of valuation allowance 266,011
 313,738
Credit carryforward 3,513
 3,995
  277,753
 348,777
Liabilities:  
  
Property, plant and equipment (612,226) (450,395)
Net deferred tax liabilities $(334,473) $(101,618)
At December 31, 2016,2018, we had a U.S. net tax operating loss carryforward of approximately $1,182.4 million,$1.16 billion, which would expire in years 20312032 through 2036.2037. We believe that the carryforward will be utilized before it expires. We recorded a $10.4$7.0 million increase to the net operating loss carryforward at December 31, 2016, for certain state losses2018 and a corresponding $5.6 million increase into the valuation allowance related to state net operating loss valuation allowance of $11.9 million.  The net decrease in the state net operating losses after reduction for the valuation allowance was $1.5 million.losses. The total valuation allowance on state net operating losses at December 31, 2016,2018 was $82.0$109.3 million becausesince it is not more likely than not that these additional state net operating losses will be utilized before they expire. Approximately $90.9 million of the U.S. net tax operating loss carryforward is attributable to deductions taken for employee stock awards on the company’s tax returns in excess of amounts expensed through the company’s income statement.There are no other valuation allowances. We also had an alternative minimum tax credit carryforwardenhanced oil recovery and marginal well credits of approximately $6.0 million.

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$3.5 million at December 31, 2018.

At December 31, 20162018 and 2015,2017, we had no unrecognized tax benefits that would impact our effective rate and we have made no provisions for interest or penalties related to uncertain tax positions. The tax years 20132015 through 20152017 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various

87
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


state taxing authorities which remain open to examination for tax years 20122014 through 2015.

2017. We do not anticipate the need for any significant income tax payments in the near term.


10. COMMITMENTS AND CONTINGENCIES

Lease Commitments

We have various commitments for office space and equipment under operating lease arrangements. RentDuring the years ended December 31, 2018, 2017, and 2016, rent expense for thethese operating leases totaledapproximated $13.2 million, $13.1 million, and $12.9 million, in 2016.  Rent expense was $13.2 million and $14.3 million for 2015 and 2014, respectively.

Shown below are future minimum cash payments required under these leases as of December 31, 2016.

 

 

Operating

 

(in thousands)

 

Leases

 

2017

 

$

9,585

 

2018

 

10,531

 

2019

 

10,677

 

2020

 

10,864

 

2021

 

11,085

 

Later years

 

44,181

 

Total future minimum lease payments

 

$

96,923

 

Other Commitments

2018.

(in thousands)  
2019 $9,849
2020 10,790
2021 11,000
2022 11,130
2023 11,433
Later years 20,831
Total future minimum lease payments $75,033
We have various commitments for compressor equipment under operating lease arrangements totaling $34.8 million with lease terms expiring in the next 1 - 35 months.

Other Commitments

At December 31, 2018, we had estimated commitments of $157.5approximately: (i) $498.3 million to finish drilling, completing, or performing other work on wells and completing wellsvarious other infrastructure projects in progress at December 31, 2016.

and (ii) $24.9 million to finish gathering system construction in progress. 

At December 31, 2016,2018, we had firm sales contracts to deliver approximately 46.4316.9 Bcf of natural gas over the next twenty-two months.6.1 years.  If we do not deliver this gas, is not delivered, our estimated financial commitment, calculated using the January 2019 index price, would be approximately $164.8$814.7 million.  ThisThe value of this commitment will fluctuate due to price volatility and actual volumes delivered.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

In connection with gas gathering and processing agreements, we have volume commitments over the next ten9.0 years.  At December 31, 2016, if noIf we do not deliver the committed gas is delivered,or NGLs, as the case may be, the estimated maximum amount that would be payable under these commitments, calculated as of December 31, 2018, would be approximately $220.0$336.0 million.  However, we believe no financial commitment will be due based on our current proved reserves and production levels from which we can fulfill these volumetric obligations.

We have minimum volume delivery commitments in connectionassociated with agreements to reimburse connection costs to various pipelines.  At December 31, 2016,If we do not deliver this gas, the estimated maximum amount that would be payable if no gas is deliveredunder these commitments, calculated as of December 31, 2018, would be approximately $7.9$57.3 million.  Of this total, we have accrued a liability of $2.1 million.  We may$2.5 million representing the estimated amount we will have additional liabilities associated with these delivery commitments in the future depending on our production levels and drilling results.

We have other various transportation, delivery, and facilities commitments in the normal course of business, which approximate $35.7 millionto pay due to insufficient forecasted volumes at particular connection points.

At December 31, 2016.  We currently anticipate meeting these obligations.

2018, we have various firm transportation agreements for gas pipeline capacity with end dates ranging from 2019 - 2025 under which we will have to pay an estimated $27.8 million over the remaining terms of the agreements. These agreements were entered into to support our residue marketing efforts, and we believe we have sufficient reserves that will utilize this firm transportation.


88
Table of Contents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

Litigation

In the normalordinary course of business, we haveare involved with various litigation matters. WeWhen a loss contingency exists, we assess whether it is probable that an asset has been impaired or a liability has been incurred and, if so, we determine if the probabilityamount of estimable amounts related to litigation mattersloss can be reasonably estimated, all in accordance with guidance established by the FASB, and adjust our accruals

CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

accordingly. Though some of the related claims may be significant, the resolution of them, we believe, 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. v. Helmerich & Payne, Inc.

In 2008, we recorded litigation expense of $119.6 million for the H.B. Krug, et al. v. Helmerich & Payne, Inc. trial court verdict, and began accruing additional post-judgment interest and costs for this case.

On December 13, 2013, the Oklahoma Supreme Court reversed the trial court’s $119.6 million verdict and affirmed an alternative jury verdict for $3.65 million.  The Supreme Court 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, which included related interest and costs, 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 November 3, 2015, the Oklahoma Supreme Court affirmed the trial court’s denial of prejudgment interest.  The only remaining issue is the amount of Plaintiffs’ award of attorney’s fees, which is subject to future trial and appellate court proceedings and, therefore, cannot be determined at this time.


11. RELATED PARTY TRANSACTIONS

Helmerich & Payne, Inc. (H&P)(“H&P”) provides contract drilling services to Cimarex. DrillingCimarex incurred drilling costs of approximately $80.1 million, $52.6 million, and $18.3 million were incurred by Cimarex related to suchthese services for 2016.  During 2015during the years ended December 31, 2018, 2017, and 2014, such costs were $7.9 million and $18.4 million,2016, respectively. Hans Helmerich, a director of Cimarex, is Chairman of the Board of Directors of H&P.

Lisa Stewart, who joined Cimarex’s Board


12. SUPPLEMENTAL CASH FLOW INFORMATION
  Years Ended December 31,
(in thousands) 2018 2017 2016
Cash paid during the period for:  
  
  
Interest expense (net of capitalized amounts of $19,969, $23,113, and $20,308, respectively) $45,357
 $52,245
 $59,282
Income taxes $—
 $3
 $13
Cash received for income tax refunds $760
 $111
 $1,450


89
Table of Directors in October 2015, is Chairman, President, Chief Executive Officer, and Chief Investment OfficerContents
CIMAREX ENERGY CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


13.ACQUISITIONS AND DIVESTITURES
On August 31, 2018, we closed on the divestiture of Sheridan Production Partners (Sheridan).  During 2016, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $177.6 thousand and joint interest billings of $5.2 thousand and received oil and gas revenues of $0.4 thousand and joint interest billings of $73.1 thousand from Sheridan affiliates.  During 2015, Cimarex paid certain affiliates of Sheridan oil and gas revenues of $224.2 thousand and joint interest billings of $10.4 thousand and received oil and gas revenues of $4.1 thousand and joint interest billings of $81.5 thousand from Sheridan affiliates.

Jerry Box, a director of Cimarex whose term expired May 2015, was the non-executive Chairman of the Board of Directors of Newpark Resources, Inc. (Newpark) through May 2014.  Certain subsidiaries of Newpark provided various drilling services to Cimarex. Costs of such services were $589.2 thousand through May 2014.

12. PROPERTY SALES AND ACQUISITIONS

The following sales and acquisitions were made in the ordinary course of business.  All amounts are net of customary purchase price adjustments.

There were no significant sales and acquisitions in 2016 or 2015.  We sold interests in various non-core oil and gas properties principally located in Ward County, Texas for $446.1a sales price of $544.5 million, during 2014.  Mostas adjusted to reflect the resolution of all asserted defects. As of December 31, 2018, we have received $534.6 million in net cash proceeds as adjusted for customary closing adjustments to reflect an effective date of April 1, 2018 and transaction costs. Final settlement, which will reflect customary post-closing adjustments, is scheduled to occur by the end of first quarter 2019. This divestiture did not significantly alter the relationship between capitalized costs and proved reserves, therefore, in accordance with the full cost method of accounting, no gain or loss was recognized.

On November 18, 2018, we entered into an Agreement and Plan of Merger to acquire Resolute Energy Corporation (“Resolute”) in a cash and stock transaction valued at a total purchase price of approximately $1.6 billion, including the assumption of Resolute’s long-term debt, which had an outstanding principal balance of $710.0 million as of September 30, 2018. Under the terms of the proceeds were relatedagreement, Resolute shareholders will have the right to salesreceive 0.3943 shares of producing gas wellsCimarex common stock, $35.00 per share in southwestern Kansascash, or a combination of $14.00 per share in cash and undeveloped acreage in Reagan County, Texas.  During 2014, we made property acquisitions totaling $249.7 million, most0.2366 shares of Cimarex common stock. The amount of stock and cash is subject to proration for a total stock and cash mix of 60% and 40%, respectively. The transaction, which were in our Cana area in Western Oklahoma.

is expected to be completed by the end of the first quarter 2019, is subject to the approval of Resolute shareholders and the satisfaction of certain regulatory approvals and other customary closing conditions.

90

Table of Contents
CIMAREX ENERGY CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Cash paid during the period for:

 

 

 

 

 

 

 

Interest expense (including capitalized amounts)

 

$

79,590

 

$

80,785

 

$

66,167

 

Interest capitalized

 

$

20,308

 

$

28,819

 

$

32,623

 

Income taxes

 

$

13

 

$

558

 

$

354

 

Cash received for income tax refunds

 

$

1,450

 

$

1,503

 

$

460

 

SUPPLEMENTAL ON OIL AND GAS INFORMATIONPRODUCING ACTIVITIES (UNAUDITED)




Oil and Gas Reserve InformationInformation——Proved reserve quantities are based on estimates prepared by Cimarex in accordance with guidelines established by the Securities and Exchange Commission (SEC)(“SEC”).


Reserve definitions comply with definitions of Rule 4-10(a) (1)-(32) of Regulation S-X of the SEC.  All of our reserve estimates are maintained by our internal Corporate Reservoir Engineering group, which is comprised of reservoir engineers and engineering technicians.  The objectives and management of this group are separate from and independent of the exploration and production functions of our company.  The technical employee primarily responsible for overseeing the reserve estimation process is our company’s Vice President of Corporate Engineering.  This individual graduated from the Colorado School of Mines with a Bachelor of Science degree in Engineering and has more than 2224 years of practical experience in reserve evaluation.  He has been directly involved in the annual reserve reporting process of Cimarex since 2002 and has served in his current role for the past twelve14 years.


DeGolyer and MacNaughton, an independent petroleum engineering consulting firm, reviewedperformed an independent evaluation of our estimated net reserves associated withrepresenting greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2016.2018.  The individual primarily responsible for overseeing the reviewevaluation is a Senior Vice President with DeGolyer and MacNaughton and a Registered Professional Engineer in the State of Texas with over 3734 years of experience in oil and gas reservoir studies and reserves evaluations.


Proved reserves are those quantities of oil, NGL,gas, and gas,NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.


There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures.  The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment, and material balance analysis.  Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also are involved in this estimation process.


The following table summarizes the trailing 12-monthtwelve-month index prices used in the reservereserves estimates for 2016, 2015,2018, 2017, and 2014.2016.  These prices are prior to adjustments for fixed and determinable amounts under provisions in existing contracts, location, grade, and quality.

 

 

December 31,

 

 

 

2016

 

2015

 

2014

 

Gas price per Mcf

 

$

2.48

 

$

2.59

 

$

4.35

 

Oil price per Bbl

 

$

42.75

 

$

50.28

 

$

94.99

 

NGL price per Bbl

 

$

14.37

 

$

14.41

 

$

30.89

 

 December 31,
 2018 2017 2016
Gas price per Mcf$3.10
 $2.98
 $2.48
Oil price per Bbl$65.56
 $51.34
 $42.75
NGL price per Bbl$21.03
 $19.09
 $14.37


91
Table of Contents

CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)


The following reserve data representstable sets forth our estimates onlyof our proved, proved developed, and should not be construedproved undeveloped oil, gas, and NGL reserves as being exact.

 

 

Gas

 

Oil

 

NGL

 

Total

 

 

 

(MMcf)

 

(MBbl)

 

(MBbl)

 

(MMcfe)

 

Total proved reserves:

 

 

 

 

 

 

 

 

 

December 31, 2013

 

1,293,500

 

108,533

 

92,044

 

2,496,964

 

Revisions of previous estimates

 

85,533

 

(1,039

)

4,262

 

104,873

 

Extensions and discoveries

 

420,442

 

29,155

 

36,424

 

813,911

 

Purchases of reserves

 

88,227

 

1,383

 

6,186

 

133,641

 

Production

 

(155,128

)

(15,639

)

(11,343

)

(317,022

)

Sales of properties

 

(65,841

)

(3,401

)

(2,300

)

(100,044

)

December 31, 2014

 

1,666,733

 

118,992

 

125,273

 

3,132,323

 

Revisions of previous estimates

 

(154,390

)

(14,633

)

(5,668

)

(276,192

)

Extensions and discoveries

 

183,084

 

22,859

 

18,079

 

428,714

 

Purchases of reserves

 

15

 

1

 

1

 

25

 

Production

 

(168,987

)

(18,663

)

(13,063

)

(359,343

)

Sales of properties

 

(9,503

)

(758

)

(345

)

(16,120

)

December 31, 2015

 

1,516,952

 

107,798

 

124,277

 

2,909,407

 

Revisions of previous estimates

 

5,888

 

(4,357

)

6,670

 

19,761

 

Extensions and discoveries

 

123,175

 

19,419

 

14,050

 

323,987

 

Purchases of reserves

 

959

 

1

 

—

 

965

 

Production

 

(168,227

)

(16,528

)

(14,200

)

(352,591

)

Sales of properties

 

(7,327

)

(455

)

(164

)

(11,042

)

December 31, 2016

 

1,471,420

 

105,878

 

130,633

 

2,890,487

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

December 31, 2013

 

1,060,704

 

86,665

 

69,089

 

1,995,233

 

December 31, 2014

 

1,263,957

 

100,050

 

89,630

 

2,402,033

 

December 31, 2015

 

1,129,490

 

89,189

 

87,549

 

2,189,920

 

December 31, 2016

 

1,144,720

 

92,032

 

99,176

 

2,291,966

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

December 31, 2013

 

232,796

 

21,868

 

22,955

 

501,731

 

December 31, 2014

 

402,776

 

18,942

 

35,643

 

730,290

 

December 31, 2015

 

387,462

 

18,609

 

36,728

 

719,487

 

December 31, 2016

 

326,700

 

13,846

 

31,457

 

598,521

 

Year-endof December 31, 2018, 2017, 2016, and 2015 and changes in our proved reserves declined by less than 1%for the years ended December 31, 2018, 2017, and 2016. All of our proved reserves are located entirely within the U.S.

 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MBOE)
Total proved reserves: 
  
  
  
December 31, 20151,516,952
 107,798
 124,277
 484,901
Revisions of previous estimates5,888
 (4,357) 6,670
 3,293
Extensions and discoveries123,175
 19,419
 14,050
 53,998
Purchases of reserves959
 1
 —
 161
Production(168,227) (16,528) (14,200) (58,765)
Sales of reserves(7,327) (455) (164) (1,840)
December 31, 20161,471,420
 105,878
 130,633
 481,748
Revisions of previous estimates(39,749) (1,225) (2,099) (9,951)
Extensions and discoveries363,774
 53,464
 42,692
 156,786
Purchases of reserves642
 42
 78
 227
Production(187,468) (20,861) (17,374) (69,479)
Sales of reserves(984) (60) (70) (294)
December 31, 20171,607,635
 137,238
 153,860
 559,037
Revisions of previous estimates(132,577) (4,348) 3,777
 (22,667)
Extensions and discoveries342,810
 53,763
 47,614
 158,512
Purchases of reserves3
 —
 —
 1
Production(205,837) (24,710) (21,994) (81,010)
Sales of reserves(20,713) (15,405) (3,821) (22,678)
December 31, 20181,591,321
 146,538
 179,436
 591,195
Proved developed reserves: 
  
  
  
December 31, 20151,129,490
 89,189
 87,549
 364,987
December 31, 20161,144,720
 92,032
 99,176
 381,994
December 31, 20171,334,510
 114,116
 126,227
 462,761
December 31, 20181,398,729
 116,339
 151,566
 501,027
Proved undeveloped reserves: 
  
  
  
December 31, 2015387,462
 18,609
 36,728
 119,914
December 31, 2016326,700
 13,846
 31,457
 99,754
December 31, 2017273,125
 23,122
 27,633
 96,276
December 31, 2018192,592
 30,199
 27,870
 90,168
Year-end 2018 proved reserves increased approximately 6% from year-end 20152017 proved reserves, to 2.89 Tcfe.591.2 MMBOE.  Proved natural gas reserves were 1.471.59 Tcf, proved oil reserves were 0.64 Tcfe,146.5 MMBbls, and proved NGL reserves were 0.78 Tcfe.179.4 MMBbls.  Our reserves in the Mid-ContinentPermian Basin accounted for 63%57% of total proved reserves, with the majoritynearly all of the remainder in the Permian Basin.

Mid-Continent.

During 2016,2018, we added 324.0 Bcfe158.5 MMBOE of proved reserves through extensions and discoveries, primarily in the Mid-ContinentPermian Basin and Permian Basin,Mid-Continent where we added 121.6 Bcfe120.3 MMBOE and 198.7 Bcfe,38.0 MMBOE, respectively.  In addition, we had net negative revisions of 22.7 MMBOE.  The revisions included decreases of 38.6 MMBOE for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and 7.7 MMBOE related to increases in operating expenses. These decreases were partially offset by increases of 2.7 MMBOE in price-related revisions and 20.9 MMBOE of net technical revisions. The majority of the technical revisions were related to better than expected performance from wells with initial production in late 2017 and positive adjustments to PUD reserves converted to proved developed reserves during 2018.

92
Table of Contents
CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)



During 2017, we added 156.8 MMBOE of proved reserves through extensions and discoveries, primarily in Permian Basin and Mid-Continent where we added 109.6 MMBOE and 47.2 MMBOE, respectively.  In addition, we had net negative revisions of 10.0 MMBOE.  The revisions included decreases of 41.5 MMBOE for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure and 7.3 MMBOE related to increases in operating expenses. These decreases were partially offset by increases of 31.2 MMBOE in price-related revisions and 7.6 MMBOE of net technical revisions related primarily to better than expected performance from wells with initial production in late 2016.

During 2016, we added 54.0 MMBOE of proved reserves through extensions and discoveries, primarily in Permian Basin and Mid-Continent, where we added 33.1 MMBOE and 20.3 MMBOE, respectively.  In addition, we had net positive revisions of 19.8 Bcfe.3.3 MMBOE.  The revisions included increases of 126.2 Bcfe21.0 MMBOE for net performance revisions and 138.5 Bcfe23.1 MMBOE related to decreases in operating expenses, partially offset by negative revisions of 244.9 Bcfe40.8 MMBOE due to lower commodity prices.  The performance revisions resulted primarily from positive adjustments to previously booked PUD reserves (72.3 Bcfe)(12.1 MMBOE) and better than expected performance from wells with initial production in late 2015.

During 2015, we added 428.7 Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin, where we added 176.8 Bcfe and 251.1 Bcfe, respectively.  During 2015, we had net negative reserve revisions of 276.2 Bcfe.  The significant decrease in commodity prices seen in 2015 resulted in negative revisions of 398.8 Bcfe due to prices.  In addition, 19.1 Bcfe of negative revisions were due to increases in operating expenses, which shortened the economic lives of properties.  These decreases were partially offset by net positive performance revisions of 141.7 Bcfe, which included 47.4 Bcfe for better than expected performance of PUD reserves converted to proved developed reserves during the year and positive adjustments of 95.3 Bcfe to previously booked PUD reserves.

During 2014, we added 813.9 Bcfe of proved reserves through extensions and discoveries, primarily in the Mid-Continent and Permian Basin.  In the Mid-Continent, we added 80.4 Bcfe from wells drilled and added 496.6 Bcfe of PUD reserves in our Cana area.  In the Permian Basin, development drilling added 234.3 Bcfe.

During 2014, we had net positive reserve revisions of 104.9 Bcfe.  Performance revisions were a net positive of approximately 113.4 Bcfe.  This net increase was due to better than expected performance of PUD reserves converted to proved developed reserves during the year (124.7 Bcfe) and positive adjustments to previously booked PUD reserves (10.1 Bcfe), offset by 21.4 Bcfe of net negative revisions primarily attributed to Cana area wells impacted by infill drilling.  Additionally, there were positive price revisions of 16.1 Bcfe, offset by negative revisions of 24.6 Bcfe due to increases in operating expenses, which shortened the economic lives of properties.


At December 31, 2016,2018, we had PUD reserves of 598.5 Bcfe,90.2 MMBOE, down 121.0 Bcfe,6.1 MMBOE, or 17%6%, from 719.5 Bcfe96.3 MMBOE of PUD reserves at December 31, 2015.2017.  Changes in our PUD reserves are summarized in the table below (in Bcfe).

below.

PUD Reserves
(MMBOE)
PUD reserves at December 31, 2015

2017

96.3

719.5


Converted to developed

(28.9

(104.3

)

Additions

53.8

35.6


Net revisions

(31.0

(52.3

)

PUD reserves at December 31, 2016

2018

90.2

598.5



During 2018, we invested $264.5 million to develop and convert 30% of our 2017 PUD reserves to proved developed reserves.  During 2017, we invested $69.5 million to develop and convert 10% of our 2016 PUD reserves to proved developed reserves. During 2016, we invested $97.7$108.8 million to develop and convert 14% of our 2015 PUD reserves to proved developed reserves.  Additionally, in 2016 we invested $11.1 million to develop 2015 PUD reserves that were waiting on completion at year-end and had not yet been converted to proved developed reserves. 

During 2015, we invested $246.5 million to develop PUD reserves, converting 24%2018, 50.9 MMBOE, or 95%, of our 2014 PUD reserves to proved developed reserves.  During 2014, we invested $503.5 million to develop PUD reserves, converting 56%53.8 MMBOE of our 2013 PUD reserves to proved developed reserves.

All 35.6 Bcfe of our 2016 PUD reserve additions occurred in the Permian Basin, while the remainder of the additions were in our western Oklahoma Cana area.  At December 31, 2016, all2018, 78% of our PUD reserves are associated with thiswere in the Permian Basin, while the remainder were in our western Oklahoma Cana area. We have no PUD reserves that have remained undeveloped for five years or more after initial bookingdisclosure and we have no PUD reserves whose scheduled delay to initiation of development is beyond five years of initial booking.

disclosure.


During 2016,2018, we had net negative PUD reserve revisions of 52.3 Bcfe.  This included 127.3 Bcfe removed due to lower commodity prices partially offset by positive technical adjustments31.0 MMBOE.  Of this total, 38.6 MMBOE was for the removal of 72.3 Bcfe to remaining previously booked PUD reserves.  Further, negative additional price revisions of 7.8 Bcfe to remaining PUD reserves whose development will likely be delayed beyond five years of initial disclosure. Partially offsetting this were more than offset by 10.5 Bcfe7.6 MMBOE of positive revisions duerelated primarily to lower projected operating expenses.

refinement of ownership and adjustments to hydrocarbon type curves based on recent development results.



93
Table of Contents
CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)


Costs IncurredIncurred——The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities.

 

 

Years Ended December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Costs incurred during the year:

 

 

 

 

 

 

 

Acquisition of properties

 

 

 

 

 

 

 

Proved

 

$

2,678

 

$

30

 

$

138,508

 

Unproved

 

67,961

 

41,233

 

277,099

 

Exploration

 

5,814

 

6,902

 

50,271

 

Development

 

672,842

 

823,830

 

1,664,877

 

Oil and gas expenditures

 

749,295

 

871,995

 

2,130,755

 

Property sales

 

(24,687

)

(41,276

)

(446,107

)

 

 

724,608

 

830,719

 

1,684,648

 

Asset retirement obligation, net

 

(7,950

)

(4,818

)

27,243

 

 

 

$

716,658

 

$

825,901

 

$

1,711,891

 

  Years Ended December 31,
(in thousands) 2018 2017 2016
Costs incurred during the year:  
  
  
Acquisition of properties  
  
  
Proved $62
 $938
 $2,678
Unproved 102,666
 135,565
 67,961
Exploration 6,341
 11,804
 5,814
Development 1,487,453
 1,140,548
 672,842
Oil and gas expenditures 1,596,522
 1,288,855
 749,295
Property sales (581,799) (11,680) (24,687)
  1,014,723
 1,277,175
 724,608
Asset retirement obligation, net (2,004) 9,416
 (7,950)
  $1,012,719
 $1,286,591
 $716,658

Aggregate Capitalized CostsCosts——The table below reflects the aggregate capitalized costs relating to our oil and gas producing activities at December 31, 2016.

(in thousands)

 

 

 

Proved properties

 

$

16,225,495

 

Unproved properties and properties under development, not being amortized

 

478,277

 

 

 

16,703,772

 

Less-accumulated depreciation, depletion, amortization, and impairments

 

(14,349,505

)

Net oil and gas properties

 

$

2,354,267

 

2018.


(in thousands)  
Proved properties $18,566,757
Unproved properties and properties under development, not being amortized 436,325
  19,003,082
Less-accumulated depreciation, depletion, amortization, and impairments (15,287,752)
Net oil and gas properties $3,715,330

Costs Not Being AmortizedAmortized——The following table summarizes oil and gas property costs not being amortized at December 31, 2016,2018, by year that the costs were incurred.

(in thousands)

 

 

 

2016

 

$

234,905

 

2015

 

42,808

 

2014

 

114,746

 

2013 and prior

 

85,818

 

 

 

$

478,277

 


(in thousands)  
2018 $198,949
2017 102,258
2016 39,846
2015 and prior 95,272
  $436,325

Of the costs not being amortized, $173.5$110.1 million (36%(25%) relates to unevaluated wells in progress and $48.5$46.3 million (10%(11%) is capitalized interest.  The remaining $256.3$279.9 million (54%(64%) is for land and seismic expenditures, most of which were for costs invested in our Mid-Continent regionPermian Basin ($136.9197.0 million) and our Permian Basin regionMid-Continent ($91.675.4 million).  On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized. Significant unproved properties are evaluated individually.  Unproved properties that are not considered individually significant are aggregated for evaluation purposes and related costs are transferred to the costs to be amortized quarterly based on the application of historical factors.  We expect to include these costs in the amortization computation as we continue with our exploration and development plans.



94
Table of Contents
CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)


Oil and Gas OperationsOperations——The following table contains direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated.  We have no long-term supply or purchase agreements with governments or authorities in which we act as producer.  Income tax expense related to our oil and gas operations is computed using the effective tax rate for the period.

 

 

Years Ended December 31,

 

(in thousands, except per Mcfe)

 

2016

 

2015

 

2014

 

Oil, gas and NGL revenues from production

 

$

1,221,218

 

$

1,417,538

 

$

2,372,829

 

Less operating costs and income taxes:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

757,670

 

4,033,295

 

—

 

Depletion

 

346,003

 

689,120

 

743,373

 

Asset retirement obligation

 

7,828

 

9,121

 

10,082

 

Production

 

232,002

 

299,374

 

342,304

 

Transportation, processing and other operating

 

210,144

 

183,134

 

215,246

 

Taxes other than income

 

61,946

 

84,764

 

128,793

 

Income tax expense (benefit)

 

(135,665

)

(1,410,065

)

345,688

 

 

 

1,479,928

 

3,888,743

 

1,785,486

 

Results of operations from oil and gas producing activities

 

$

(258,710

)

$

(2,471,205

)

$

587,343

 

Depletion rate per Mcfe

 

$

0.98

 

$

1.92

 

$

2.34

 

period, with the 2017 effective tax rate adjusted to remove the impact of the reduction in the federal statutory rate.


  Years Ended December 31,
(in thousands, except per��BOE) 2018 2017 2016
Oil, gas, and NGL revenues from production $2,297,645
 $1,874,003
 $1,221,218
Less operating costs and income taxes:  
  
  
Impairment of oil and gas properties —
 —
 757,670
Depletion 538,919
 399,328
 346,003
Asset retirement obligation 7,142
 15,624
 7,828
Production 293,213
 262,180
 232,002
Transportation, processing, and other operating 218,614
 254,730
 210,144
Taxes other than income 125,169
 89,864
 61,946
Income tax expense (benefit) 251,897
 310,937
 (135,665)
  1,434,954
 1,332,663
 1,479,928
Results of operations from oil and gas producing activities $862,691
 $541,340
 $(258,710)
Depletion rate per BOE $6.65
 $5.75
 $5.89

Standardized Measure of Future Net Cash FlowsFlows——The “StandardizedStandardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” (Standardized Measure)Reserves (“Standardized Measure”) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, varying price and cost assumptions, and risks inherent in reserve estimates.


Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves.  Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow.  Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties.  Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.


The following summary sets forth our Standardized Measure.

 

 

December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Cash inflows

 

$

7,576,211

 

$

8,839,485

 

$

19,892,471

 

Production costs

 

(2,970,891

)

(3,521,881

)

(5,777,710

)

Development costs

 

(794,298

)

(1,058,020

)

(1,453,860

)

Income tax expense

 

(507,145

)

(728,029

)

(3,768,780

)

Net cash flow

 

3,303,877

 

3,531,555

 

8,892,121

 

10% annual discount rate

 

(1,411,259

)

(1,597,424

)

(4,539,276

)

Standardized measure of discounted future net cash flow

 

$

1,892,618

 

$

1,934,131

 

$

4,352,845

 


  December 31,
(in thousands) 2018 2017 2016
Future cash inflows $14,050,367
 $11,967,325
 $7,576,211
Future production costs (4,889,601) (4,360,599) (2,970,891)
Future development costs (1,017,318) (948,735) (794,298)
Future income tax expenses (1,303,762) (882,519) (507,145)
Future net cash flows 6,839,686
 5,775,472
 3,303,877
10% annual discount for estimated timing of cash flows (2,824,499) (2,490,471) (1,411,259)
Standardized measure of discounted future net cash flows $4,015,187
 $3,285,001
 $1,892,618

95
Table of Contents
CIMAREX ENERGY CO.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)


The estimates of cash flows and reserve quantities shown above are based upon the unweighted trailing twelve-month average 12 month first-day-of-the-month benchmark prices.  See table above underOil and Gas Reserve Information for prices used in determining the Standardized Measure.  If future gas sales are covered by contracts at specified prices, the contract prices would be used.  Prices are market driven and will fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors.

The following are the principal sources of change in the Standardized Measure.

 

 

December 31,

 

(in thousands)

 

2016

 

2015

 

2014

 

Standardized Measure, beginning of period

 

$

1,934,131

 

$

4,352,845

 

$

3,598,894

 

Sales, net of production costs

 

(717,126

)

(850,267

)

(1,686,486

)

Net change in sales prices, net of production costs

 

(429,956

)

(4,262,261

)

(176,200

)

Extensions and discoveries, net of future production and development costs

 

517,702

 

573,373

 

1,633,285

 

Changes in future development costs

 

167,387

 

280,163

 

23,025

 

Previously estimated development costs incurred during the period

 

110,945

 

214,749

 

442,780

 

Revision of quantity estimates

 

15,701

 

(240,063

)

230,673

 

Accretion of discount

 

227,904

 

638,948

 

520,058

 

Change in income taxes

 

115,609

 

1,691,721

 

(434,949

)

Purchases of reserves in place

 

429

 

20

 

228,539

 

Sales of properties

 

(9,440

)

(26,225

)

(185,326

)

Change in production rates and other

 

(40,668

)

(438,872

)

158,552

 

Standardized Measure, end of period

 

$

1,892,618

 

$

1,934,131

 

$

4,352,845

 

  Years Ended December 31,
(in thousands) 2018 2017 2016
Standardized Measure, beginning of period $3,285,001
 $1,892,618
 $1,934,131
Sales, net of production costs (1,660,649) (1,267,229) (717,126)
Net change in sales prices, net of production costs 377,178
 855,024
 (429,956)
Extensions and discoveries, net of future production and development costs 1,738,993
 1,443,577
 517,702
Changes in future development costs 194,523
 298,819
 167,387
Previously estimated development costs incurred during the period 335,954
 78,398
 110,945
Revision of quantity estimates 96,783
 (65,376) 15,701
Accretion of discount 372,482
 212,192
 227,904
Change in income taxes (284,186) (210,519) 115,609
Purchases of reserves in place —
 2,255
 429
Sales of reserves (300,592) (1,666) (9,440)
Change in production rates and other (140,300) 46,908
 (40,668)
Standardized Measure, end of period $4,015,187
 $3,285,001
 $1,892,618


96

Table of Contents
CIMAREX ENERGY CO.

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)

 

 

Quarter

 

2016

 

First

 

Second

 

Third

 

Fourth

 

(in thousands, except per share data)

 

 

 

 

 

 

 

 

 

Revenues

 

$

240,600

 

$

298,873

 

$

335,717

 

$

382,155

 

Expenses, net (1)

 

472,059

 

513,327

 

346,390

 

334,372

 

Net income (loss)

 

$

(231,459

)

$

(214,454

)

$

(10,673

)

$

47,783

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.08

 

$

0.08

 

$

0.08

 

$

0.08

 

Undistributed

 

(2.57

)

(2.39

)

(0.20

)

0.42

 

 

 

$

(2.49

)

$

(2.31

)

$

(0.12

)

$

0.50

 

Diluted:

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.08

 

$

0.08

 

$

0.08

 

$

0.08

 

Undistributed

 

(2.57

)

(2.39

)

(0.20

)

0.42

 

 

 

$

(2.49

)

$

(2.31

)

$

(0.12

)

$

0.50

 


(1)         The 2016 quarterly expenses, net include non-cash impairments to our oil and gas properties of $318.8 million (or $3.43 per diluted share), $333.3 million (or $3.58 per diluted share), and $105.6 million (or $1.13 per diluted share) for the first quarter through the third quarter of 2016, respectively, as discussed in Note 1 to the Consolidated Financial Statements under Oil and Gas Properties.

 

 

Quarter

 

2015

 

First

 

Second

 

Third

 

Fourth

 

(in thousands, except per share data)

 

 

 

 

 

 

 

 

 

Revenues

 

$

361,002

 

$

424,283

 

$

356,055

 

$

311,279

 

Expenses, net (1)

 

910,572

 

1,014,768

 

1,087,355

 

1,019,528

 

Net loss

 

$

(549,570

)

$

(590,485

)

$

(731,300

)

$

(708,249

)

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.16

 

$

0.16

 

$

0.16

 

$

0.16

 

Undistributed

 

(6.57

)

(6.52

)

(8.03

)

(7.78

)

 

 

$

(6.41

)

$

(6.36

)

$

(7.87

)

$

(7.62

)

Diluted:

 

 

 

 

 

 

 

 

 

Distributed

 

$

0.16

 

$

0.16

 

$

0.16

 

$

0.16

 

Undistributed

 

(6.57

)

(6.52

)

(8.03

)

(7.78

)

 

 

$

(6.41

)

$

(6.36

)

$

(7.87

)

$

(7.62

)


(1)         The 2015 quarterly expenses, net include non-cash impairments to our oil and gas properties of $821.2 million (or $9.57 per diluted share), $966.0 million (or $10.41 per diluted share), $1.1 billion (or $12.31 per diluted share) and $1.1 billion (or $11.85 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 1 to the Consolidated Financial Statements under Oil and Gas Properties.

  Quarter
2018 First Second Third Fourth
(in thousands, except per share data)        
Revenues $567,134
 $556,274
 $591,488
 $624,121
Expenses, net 380,816
 415,277
 443,134
 307,939
Net income $186,318
 $140,997
 $148,354
 $316,182
Earnings per share to common stockholders:  
  
  
  
Basic $1.96
 $1.48
 $1.56
 $3.32
Diluted $1.96
 $1.48
 $1.56
 $3.32
  Quarter
2017 First Second Third Fourth
(in thousands, except per share data)        
Revenues $447,176
 $456,452
 $463,681
 $550,940
Expenses, net 316,204
 359,190
 372,282
 376,244
Net income $130,972
 $97,262
 $91,399
 $174,696
Earnings per share to common stockholders:  
  
  
  
Basic $1.38
 $1.02
 $0.96
 $1.83
Diluted $1.38
 $1.02
 $0.96
 $1.83

The sum of the individual quarterly net incomeearnings per common share amounts doesmay not agree with year-to-date net incomeearnings per common share because each quarter’s computation is based on the number of shares outstanding at the end of the applicable quarter using the two-class method.

Impact



97
Table of Correcting Adjustments on Unaudited Quarterly Financial Statements (see Note 1)

The following tables present corrected unaudited consolidated balance sheets as of March 31, June 30, and September 30, 2016, corrected unaudited consolidated statements of operations and comprehensive income (loss) for the three months ended March 31, June 30, and September 30, 2016 and 2015, the six months ended June 30, 2016, and the nine months ended September 30, 2016, and corrected unaudited consolidated statements of cash

Contents

flows for the three months ended March 31, 2016 and 2015, the six months ended June 30, 2016 and 2015, and the nine months ended September 30, 2016 and 2015.

 

 

Condensed Consolidated Balance Sheet
March 31, 2016

 

(in thousands, except share and per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

676,639

 

$

 

 

$

676,639

 

Receivables, net

 

192,160

 

 

 

192,160

 

Oil and gas well equipment and supplies

 

44,648

 

 

 

44,648

 

Derivative instruments

 

11,868

 

 

 

11,868

 

Prepaid expenses

 

5,425

 

 

 

5,425

 

Other current assets

 

350

 

 

 

350

 

Total current assets

 

931,090

 

 

 

931,090

 

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

 

 

 

 

 

 

 

Proved properties

 

15,677,599

 

 

 

15,677,599

 

Unproved properties and properties under development, not being amortized

 

466,497

 

 

 

466,497

 

 

 

16,144,096

 

 

 

16,144,096

 

Less-accumulated depreciation, depletion and amortization and impairment

 

(13,057,470

)

(606,055

)

(13,663,525

)

Net oil and gas properties

 

3,086,626

 

(606,055

)

2,480,571

 

Fixed assets, net

 

227,343

 

 

 

227,343

 

Goodwill

 

620,232

 

 

 

620,232

 

Derivative instruments

 

422

 

 

 

422

 

Other assets, net

 

35,548

 

 

 

35,548

 

 

 

$

4,901,261

 

$

(606,055

)

$

4,295,206

 

 

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

39,241

 

$

 

 

$

39,241

 

Accrued liabilities

 

229,787

 

 

 

229,787

 

Derivative instruments

 

3,812

 

 

 

3,812

 

Revenue payable

 

84,252

 

 

 

84,252

 

Total current liabilities

 

357,092

 

 

 

357,092

 

Long-term debt:

 

 

 

 

 

 

 

Principal

 

1,500,000

 

 

 

1,500,000

 

Less-unamortized debt issuance costs

 

(13,789

)

 

 

(13,789

)

Long-term debt, net

 

1,486,211

 

 

 

1,486,211

 

Deferred income taxes

 

246,553

 

(221,406

)

25,147

 

Other liabilities

 

197,074

 

 

 

197,074

 

Total liabilities

 

2,286,930

 

(221,406

)

2,065,524

 

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, 94,815,010 shares issued

 

948

 

 

 

948

 

Paid-in capital

 

2,773,254

 

 

 

2,773,254

 

Retained earnings (accumulated deficit)

 

(160,397

)

(384,649

)

(545,046

)

Accumulated other comprehensive income

 

526

 

 

 

526

 

 

 

2,614,331

 

(384,649

)

2,229,682

 

 

 

$

4,901,261

 

$

(606,055

)

$

4,295,206

 

 

 

Condensed Consolidated Balance Sheet
June 30, 2016

 

(in thousands, except share and per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

641,739

 

$

 

 

$

641,739

 

Receivables, net

 

229,634

 

 

 

229,634

 

Oil and gas well equipment and supplies

 

37,852

 

 

 

37,852

 

Derivative instruments

 

1,119

 

 

 

1,119

 

Prepaid expenses

 

5,090

 

 

 

5,090

 

Other current assets

 

2,173

 

 

 

2,173

 

Total current assets

 

917,607

 

 

 

917,607

 

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

 

 

 

 

 

 

 

Proved properties

 

15,845,260

 

 

 

15,845,260

 

Unproved properties and properties under development, not being amortized

 

458,530

 

 

 

458,530

 

 

 

16,303,790

 

 

 

16,303,790

 

Less-accumulated depreciation, depletion and amortization and impairment

 

(13,569,032

)

(518,361

)

(14,087,393

)

Net oil and gas properties

 

2,734,758

 

(518,361

)

2,216,397

 

Fixed assets, net

 

224,056

 

 

 

224,056

 

Goodwill

 

620,232

 

 

 

620,232

 

Deferred income taxes

 

—

 

97,101

 

97,101

 

Derivative instruments

 

—

 

 

 

—

 

Other assets, net

 

35,170

 

 

 

35,170

 

 

 

$

4,531,823

 

$

(421,260

)

$

4,110,563

 

 

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

55,564

 

$

 

 

$

55,564

 

Accrued liabilities

 

220,154

 

 

 

220,154

 

Derivative instruments

 

28,399

 

 

 

28,399

 

Revenue payable

 

99,209

 

 

 

99,209

 

Total current liabilities

 

403,326

 

 

 

403,326

 

Long-term debt:

 

 

 

 

 

 

 

Principal

 

1,500,000

 

 

 

1,500,000

 

Less-unamortized debt issuance costs

 

(13,205

)

 

 

(13,205

)

Long-term debt, net

 

1,486,795

 

 

 

1,486,795

 

Deferred income taxes

 

92,446

 

(92,446

)

—

 

Other liabilities

 

202,454

 

 

 

202,454

 

Total liabilities

 

2,185,021

 

(92,446

)

2,092,575

 

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, 94,986,852 shares issued

 

950

 

 

 

950

 

Paid-in capital

 

2,775,805

 

 

 

2,775,805

 

Retained earnings (accumulated deficit)

 

(430,674

)

(328,814

)

(759,488

)

Accumulated other comprehensive income

 

721

 

 

 

721

 

Total stockholders’ equity

 

2,346,802

 

(328,814

)

2,017,988

 

 

 

$

4,531,823

 

$

(421,260

)

$

4,110,563

 

 

 

Condensed Consolidated Balance Sheet
September 30, 2016

 

(in thousands, except share and per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

698,696

 

$

 

 

$

698,696

 

Receivables, net

 

226,983

 

 

 

226,983

 

Oil and gas well equipment and supplies

 

34,909

 

 

 

34,909

 

Derivative instruments

 

1,147

 

 

 

1,147

 

Prepaid expenses

 

3,453

 

 

 

3,453

 

Other current assets

 

1,315

 

 

 

1,315

 

Total current assets

 

966,503

 

 

 

966,503

 

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

 

 

 

 

 

 

 

Proved properties

 

16,013,316

 

 

 

16,013,316

 

Unproved properties and properties under development, not being amortized

 

447,071

 

 

 

447,071

 

 

 

16,460,387

 

 

 

16,460,387

 

Less-accumulated depreciation, depletion and amortization and impairment

 

(13,756,311

)

(515,071

)

(14,271,382

)

Net oil and gas properties

 

2,704,076

 

(515,071

)

2,189,005

 

Fixed assets, net

 

214,448

 

 

 

214,448

 

Goodwill

 

620,232

 

 

 

620,232

 

Deferred income taxes

 

—

 

100,880

 

100,880

 

Derivative instruments

 

3

 

 

 

3

 

Other assets, net

 

33,485

 

 

 

33,485

 

 

 

$

4,538,747

 

$

(414,191

)

$

4,124,556

 

 

 

 

 

 

 

 

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

 

$

53,428

 

$

 

 

$

53,428

 

Accrued liabilities

 

258,551

 

 

 

258,551

 

Derivative instruments

 

21,573

 

 

 

21,573

 

Revenue payable

 

107,766

 

 

 

107,766

 

Total current liabilities

 

441,318

 

 

 

441,318

 

Long-term debt:

 

 

 

 

 

 

 

Principal

 

1,500,000

 

 

 

1,500,000

 

Less-unamortized debt issuance costs

 

(12,629

)

 

 

(12,629

)

Long-term debt, net

 

1,487,371

 

 

 

1,487,371

 

Deferred income taxes

 

87,523

 

(87,523

)

—

 

Other liabilities

 

189,253

 

 

 

189,253

 

Total liabilities

 

2,205,465

 

(87,523

)

2,117,942

 

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, 94,964,174 shares issued

 

950

 

 

 

950

 

Paid-in capital

 

2,774,804

 

 

 

2,774,804

 

Retained earnings (accumulated deficit)

 

(443,480

)

(326,668

)

(770,148

)

Accumulated other comprehensive income

 

1,008

 

 

 

1,008

 

Total stockholders’ equity

 

2,333,282

 

(326,668

)

2,006,614

 

 

 

$

4,538,747

 

$

(414,191

)

$

4,124,556

 

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
March 31, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

117,573

 

$

 

 

$

117,573

 

Gas sales

 

82,608

 

 

 

82,608

 

NGL sales

 

33,352

 

 

 

33,352

 

Gas gathering and other

 

7,241

 

 

 

7,241

 

Gas marketing, net

 

(174

)

 

 

(174

)

 

 

240,600

 

 

 

240,600

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

230,132

 

88,654

 

318,786

 

Depreciation, depletion and amortization

 

128,099

 

(17,463

)

110,636

 

Asset retirement obligation

 

2,298

 

 

 

2,298

 

Production

 

70,702

 

 

 

70,702

 

Transportation, processing, and other operating

 

46,443

 

 

 

46,443

 

Gas gathering and other

 

8,080

 

 

 

8,080

 

Taxes other than income

 

13,839

 

 

 

13,839

 

General and administrative

 

13,897

 

 

 

13,897

 

Stock compensation

 

5,528

 

 

 

5,528

 

(Gain) loss on derivative instruments, net

 

(428

)

 

 

(428

)

Other operating, net

 

90

 

 

 

90

 

 

 

518,680

 

71,191

 

589,871

 

Operating income (loss)

 

(278,080

)

(71,191

)

(349,271

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

20,805

 

 

 

20,805

 

Capitalized interest

 

(4,904

)

 

 

(4,904

)

Other, net

 

(1,650

)

 

 

(1,650

)

Income (loss) before income tax

 

(292,331

)

(71,191

)

(363,522

)

Income tax expense (benefit)

 

(106,200

)

(25,863

)

(132,063

)

Net income (loss)

 

$

(186,131

)

$

(45,328

)

$

(231,459

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(2.00

)

$

(0.49

)

$

(2.49

)

Diluted

 

$

(2.00

)

$

(0.49

)

$

(2.49

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.08

 

$

 

 

$

0.08

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(186,131

)

$

(45,328

)

$

(231,459

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

85

 

 

 

85

 

Total comprehensive income (loss)

 

$

(186,046

)

$

(45,328

)

$

(231,374

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
June 30, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

162,005

 

$

 

 

$

162,005

 

Gas sales

 

76,615

 

 

 

76,615

 

NGL sales

 

51,939

 

 

 

51,939

 

Gas gathering and other

 

8,211

 

 

 

8,211

 

Gas marketing, net

 

103

 

 

 

103

 

 

 

298,873

 

 

 

298,873

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

399,194

 

(65,903

)

333,291

 

Depreciation, depletion and amortization

 

123,877

 

(21,791

)

102,086

 

Asset retirement obligation

 

1,750

 

 

 

1,750

 

Production

 

57,213

 

 

 

57,213

 

Transportation, processing, and other operating

 

44,436

 

 

 

44,436

 

Gas gathering and other

 

7,492

 

 

 

7,492

 

Taxes other than income

 

14,066

 

 

 

14,066

 

General and administrative

 

21,424

 

 

 

21,424

 

Stock compensation

 

7,490

 

 

 

7,490

 

(Gain) loss on derivative instruments, net

 

33,236

 

 

 

33,236

 

Other operating, net

 

24

 

 

 

24

 

 

 

710,202

 

(87,694

)

622,508

 

Operating income (loss)

 

(411,329

)

87,694

 

(323,635

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

20,824

 

 

 

20,824

 

Capitalized interest

 

(5,633

)

 

 

(5,633

)

Other, net

 

(2,011

)

 

 

(2,011

)

Income (loss) before income tax

 

(424,509

)

87,694

 

(336,815

)

Income tax expense (benefit)

 

(154,219

)

31,858

 

(122,361

)

Net income (loss)

 

$

(270,290

)

$

55,836

 

$

(214,454

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(2.91

)

$

0.60

 

$

(2.31

)

Diluted

 

$

(2.91

)

$

0.60

 

$

(2.31

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.08

 

$

 

 

$

0.08

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(270,290

)

$

55,836

 

$

(214,454

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

195

 

 

 

195

 

Total comprehensive income (loss)

 

$

(270,095

)

$

55,836

 

$

(214,259

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Six Months Ended
June 30, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

279,578

 

$

 

 

$

279,578

 

Gas sales

 

159,223

 

 

 

159,223

 

NGL sales

 

85,291

 

 

 

85,291

 

Gas gathering and other

 

15,452

 

 

 

15,452

 

Gas marketing, net

 

(71

)

 

 

(71

)

 

 

539,473

 

 

 

539,473

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

629,326

 

22,751

 

652,077

 

Depreciation, depletion and amortization

 

251,976

 

(39,254

)

212,722

 

Asset retirement obligation

 

4,048

 

 

 

4,048

 

Production

 

127,915

 

 

 

127,915

 

Transportation, processing, and other operating

 

90,879

 

 

 

90,879

 

Gas gathering and other

 

15,572

 

 

 

15,572

 

Taxes other than income

 

27,905

 

 

 

27,905

 

General and administrative

 

35,321

 

 

 

35,321

 

Stock compensation

 

13,018

 

 

 

13,018

 

(Gain) loss on derivative instruments, net

 

32,808

 

 

 

32,808

 

Other operating, net

 

114

 

 

 

114

 

 

 

1,228,882

 

(16,503

)

1,212,379

 

Operating income (loss)

 

(689,409

)

16,503

 

(672,906

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

41,629

 

 

 

41,629

 

Capitalized interest

 

(10,537

)

 

 

(10,537

)

Other, net

 

(3,661

)

 

 

(3,661

)

Income (loss) before income tax

 

(716,840

)

16,503

 

(700,337

)

Income tax expense (benefit)

 

(260,419

)

5,995

 

(254,424

)

Net income (loss)

 

$

(456,421

)

$

10,508

 

$

(445,913

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(4.91

)

$

0.12

 

$

(4.79

)

Diluted

 

$

 (4.91

)

$

0.12

 

$

 (4.79

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

 0.16

 

$

 

 

$

0.16

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(456,421

)

$

10,508

 

$

(445,913

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

280

 

 

 

280

 

Total comprehensive income (loss)

 

$

(456,141

)

$

10,508

 

$

(445,633

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
September 30, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$166,079

 

$

 

$166,079

 

Gas sales

 

109,278

 

 

 

109,278

 

NGL sales

 

50,464

 

 

 

50,464

 

Gas gathering and other

 

9,824

 

 

 

9,824

 

Gas marketing, net

 

72

 

 

 

72

 

 

 

335,717

 

 

 

335,717

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

89,816

 

15,777

 

105,593

 

Depreciation, depletion and amortization

 

109,344

 

(19,067

)

90,277

 

Asset retirement obligation

 

2,033

 

 

 

2,033

 

Production

 

52,976

 

 

 

52,976

 

Transportation, processing, and other operating

 

48,706

 

 

 

48,706

 

Gas gathering and other

 

7,905

 

 

 

7,905

 

Taxes other than income

 

15,974

 

 

 

15,974

 

General and administrative

 

20,118

 

 

 

20,118

 

Stock compensation

 

5,764

 

 

 

5,764

 

(Gain) loss on derivative instruments, net

 

(9,758

)

 

 

(9,758

)

Other operating, net

 

179

 

 

 

179

 

 

 

343,057

 

(3,290

)

339,767

 

Operating income (loss)

 

(7,340

)

3,290

 

(4,050

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

20,931

 

 

 

20,931

 

Capitalized interest

 

(5,421

)

 

 

(5,421

)

Other, net

 

(3,828

)

 

 

(3,828

)

Income (loss) before income tax

 

(19,022

)

3,290

 

(15,732

)

Income tax expense (benefit)

 

(6,204

)

1,145

 

(5,059

)

Net income (loss)

 

$(12,818

)

$2,145

 

$(10,673

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$(0.14

)

$0.02

 

$(0.12

)

Diluted

 

$(0.14

)

$0.02

 

$(0.12

)

 

 

 

 

 

 

 

 

Dividends per share

 

$0.08

 

$

 

$0.08

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$(12,818

)

$2,145

 

$(10,673

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

287

 

 

 

287

 

Total comprehensive income (loss)

 

$(12,531

)

$2,145

 

$(10,386

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Nine Months Ended
September 30, 2016

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

445,657

 

$

 

 

$

445,657

 

Gas sales

 

268,501

 

 

 

268,501

 

NGL sales

 

135,755

 

 

 

135,755

 

Gas gathering and other

 

25,276

 

 

 

25,276

 

Gas marketing, net

 

1

 

 

 

1

 

 

 

875,190

 

 

 

875,190

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

719,142

 

38,528

 

757,670

 

Depreciation, depletion and amortization

 

361,320

 

(58,321

)

302,999

 

Asset retirement obligation

 

6,081

 

 

 

6,081

 

Production

 

180,891

 

 

 

180,891

 

Transportation, processing, and other operating

 

139,585

 

 

 

139,585

 

Gas gathering and other

 

23,477

 

 

 

23,477

 

Taxes other than income

 

43,879

 

 

 

43,879

 

General and administrative

 

55,439

 

 

 

55,439

 

Stock compensation

 

18,782

 

 

 

18,782

 

(Gain) loss on derivative instruments, net

 

23,050

 

 

 

23,050

 

Other operating, net

 

293

 

 

 

293

 

 

 

1,571,939

 

(19,793

)

1,552,146

 

Operating income (loss)

 

(696,749

)

19,793

 

(676,956

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

62,560

 

 

 

62,560

 

Capitalized interest

 

(15,958

)

 

 

(15,958

)

Other, net

 

(7,489

)

 

 

(7,489

)

Income (loss) before income tax

 

(735,862

)

19,793

 

(716,069

)

Income tax expense (benefit)

 

(266,623

)

7,140

 

(259,483

)

Net income (loss)

 

$

(469,239

)

$

12,653

 

$

(456,586

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(5.04

)

$

0.14

 

$

(4.90

)

Diluted

 

$

(5.04

)

$

0.14

 

$

(4.90

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.24

 

$

 

 

$

0.24

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(469,239

)

$

12,653

 

$

(456,586

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

567

 

 

 

567

 

Total comprehensive income (loss)

 

$

(468,672

)

$

12,653

 

$

(456,019

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
March 31, 2015

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

196,005

 

$

 

 

$

196,005

 

Gas sales

 

110,962

 

 

 

110,962

 

NGL sales

 

45,600

 

 

 

45,600

 

Gas gathering and other

 

8,270

 

 

 

8,270

 

Gas marketing, net

 

165

 

 

 

165

 

 

 

361,002

 

 

 

361,002

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

603,599

 

217,585

 

821,184

 

Depreciation, depletion and amortization

 

216,778

 

(7,107

)

209,671

 

Asset retirement obligation

 

1,736

 

 

 

1,736

 

Production

 

82,211

 

 

 

82,211

 

Transportation, processing, and other operating

 

39,642

 

 

 

39,642

 

Gas gathering and other

 

8,864

 

 

 

8,864

 

Taxes other than income

 

21,981

 

 

 

21,981

 

General and administrative

 

15,938

 

 

 

15,938

 

Stock compensation

 

5,155

 

 

 

5,155

 

(Gain) loss on derivative instruments, net

 

—

 

 

 

—

 

Other operating, net

 

524

 

 

 

524

 

 

 

996,428

 

210,478

 

1,206,906

 

Operating income (loss)

 

(635,426

)

(210,478

)

(845,904

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

21,256

 

 

 

21,256

 

Capitalized interest

 

(9,417

)

 

 

(9,417

)

Other, net

 

(3,585

)

 

 

(3,585

)

Income (loss) before income tax

 

(643,680

)

(210,478

)

(854,158

)

Income tax expense (benefit)

 

(228,739

)

(75,849

)

(304,588

)

Net income (loss)

 

$

(414,941

)

$

(134,629

)

$

(549,570

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(4.84

)

$

(1.57

)

$

(6.41

)

Diluted

 

$

(4.84

)

$

(1.57

)

$

(6.41

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.16

 

$

 

 

$

0.16

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(414,941

)

$

(134,629

)

$

(549,570

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

101

 

 

 

101

 

Total comprehensive income (loss)

 

$

(414,840

)

$

(134,629

)

$

(549,469

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
June 30, 2015

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

259,344

 

$

 

 

$

259,344

 

Gas sales

 

106,374

 

 

 

106,374

 

NGL sales

 

49,477

 

 

 

49,477

 

Gas gathering and other

 

9,141

 

 

 

9,141

 

Gas marketing, net

 

(53

)

 

 

(53

)

 

 

424,283

 

 

 

424,283

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

967,287

 

(1,270

)

966,017

 

Depreciation, depletion and amortization

 

217,451

 

(14,176

)

203,275

 

Asset retirement obligation

 

2,042

 

 

 

2,042

 

Production

 

70,600

 

 

 

70,600

 

Transportation, processing, and other operating

 

43,713

 

 

 

43,713

 

Gas gathering and other

 

11,306

 

 

 

11,306

 

Taxes other than income

 

25,980

 

 

 

25,980

 

General and administrative

 

14,054

 

 

 

14,054

 

Stock compensation

 

4,988

 

 

 

4,988

 

(Gain) loss on derivative instruments, net

 

—

 

 

 

—

 

Other operating, net

 

260

 

 

 

260

 

 

 

1,357,681

 

(15,446

)

1,342,235

 

Operating income (loss)

 

(933,398

)

15,446

 

(917,952

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

21,297

 

 

 

21,297

 

Capitalized interest

 

(8,570

)

 

 

(8,570

)

Other, net

 

(3,854

)

 

 

(3,854

)

Income (loss) before income tax

 

(942,271

)

15,446

 

(926,825

)

Income tax expense (benefit)

 

(342,056

)

5,716

 

(336,340

)

Net income (loss)

 

$

(600,215

)

$

9,730

 

$

(590,485

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(6.47

)

$

0.11

 

$

(6.36

)

Diluted

 

$

(6.47

)

$

0.11

 

$

(6.36

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.16

 

$

 

 

$

0.16

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(600,215

)

$

9,730

 

$

(590,485

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

(292

)

 

 

(292

)

Total comprehensive income (loss)

 

$

(600,507

)

$

9,730

 

$

(590,777

)

 

 

Condensed Consolidated Statement of Operations and
Comprehensive Income (Loss) for the Three Months Ended
September 30, 2015

 

(in thousands, except per share data)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Revenues:

 

 

 

 

 

 

 

Oil sales

 

$

192,501

 

$

 

 

$

192,501

 

Gas sales

 

114,649

 

 

 

114,649

 

NGL sales

 

40,159

 

 

 

40,159

 

Gas gathering and other

 

8,754

 

 

 

8,754

 

Gas marketing, net

 

(8

)

 

 

(8

)

 

 

356,055

 

 

 

356,055

 

Costs and expenses:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

1,180,649

 

(36,188

)

1,144,461

 

Depreciation, depletion and amortization

 

185,654

 

(13,756

)

171,898

 

Asset retirement obligation

 

2,615

 

 

 

2,615

 

Production

 

69,334

 

 

 

69,334

 

Transportation, processing, and other operating

 

46,290

 

 

 

46,290

 

Gas gathering and other

 

8,429

 

 

 

8,429

 

Taxes other than income

 

19,717

 

 

 

19,717

 

General and administrative

 

20,413

 

 

 

20,413

 

Stock compensation

 

4,737

 

 

 

4,737

 

(Gain) loss on derivative instruments, net

 

(1,968

)

 

 

(1,968

)

Other operating, net

 

60

 

 

 

60

 

 

 

1,535,930

 

(49,944

)

1,485,986

 

Operating income (loss)

 

(1,179,875

)

49,944

 

(1,129,931

)

Other (income) and expense:

 

 

 

 

 

 

 

Interest expense

 

21,416

 

 

 

21,416

 

Capitalized interest

 

(7,100

)

 

 

(7,100

)

Other, net

 

(2,375

)

 

 

(2,375

)

Income (loss) before income tax

 

(1,191,816

)

49,944

 

(1,141,872

)

Income tax expense (benefit)

 

(428,532

)

17,960

 

(410,572

)

Net income (loss)

 

$

(763,284

)

$

31,984

 

$

(731,300

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share to common stockholders:

 

 

 

 

 

 

 

Basic

 

$

(8.21

)

$

0.34

 

$

(7.87

)

Diluted

 

$

(8.21

)

$

0.34

 

$

(7.87

)

 

 

 

 

 

 

 

 

Dividends per share

 

$

0.16

 

$

 

 

$

0.16

 

 

 

 

 

 

 

 

 

Comprehensive income (loss):

 

 

 

 

 

 

 

Net income (loss)

 

$

(763,284

)

$

31,984

 

$

(731,300

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

Change in fair value of investments, net of tax

 

(609

)

 

 

(609

)

Total comprehensive income (loss)

 

$

(763,893

)

$

31,984

 

$

(731,909

)

 

 

Condensed Consolidated Statement of Cash Flows
for the Three Months Ended
March 31, 2016

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(186,131

)

$

(45,328

)

$

(231,459

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

230,132

 

88,654

 

318,786

 

Depreciation, depletion and amortization

 

128,099

 

(17,463

)

110,636

 

Asset retirement obligation

 

2,298

 

 

 

2,298

 

Deferred income taxes

 

(106,200

)

(25,863

)

(132,063

)

Stock compensation

 

5,528

 

 

 

5,528

 

(Gain) loss on derivative instruments

 

(428

)

 

 

(428

)

Settlements on derivative instruments

 

5,068

 

 

 

5,068

 

Changes in non-current assets and liabilities

 

1,863

 

 

 

1,863

 

Other, net

 

1,362

 

 

 

1,362

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

33,147

 

 

 

33,147

 

Other current assets

 

11,982

 

 

 

11,982

 

Accounts payable and other current liabilities

 

(41,660

)

 

 

(41,660

)

Net cash provided by operating activities

 

85,060

 

 

 

85,060

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(176,395

)

 

 

(176,395

)

Sales of oil and gas assets and other assets

 

13,059

 

 

 

13,059

 

Other capital expenditures

 

(9,477

)

 

 

(9,477

)

Net cash used by investing activities

 

(172,813

)

 

 

(172,813

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Dividends paid

 

(15,104

)

 

 

(15,104

)

Proceeds from exercise of stock options and other

 

114

 

 

 

114

 

Net cash provided by (used in) financing activities

 

(14,990

)

 

 

(14,990

)

Net change in cash and cash equivalents

 

(102,743

)

 

 

(102,743

)

Cash and cash equivalents at beginning of period

 

779,382

 

 

 

779,382

 

Cash and cash equivalents at end of period

 

$

676,639

 

 

 

$

676,639

 

 

 

Condensed Consolidated Statement of Cash Flows
for the Six Months Ended
June 30, 2016

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(456,421

)

$

10,508

 

$

(445,913

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

629,326

 

22,751

 

652,077

 

Depreciation, depletion and amortization

 

251,976

 

(39,254

)

212,722

 

Asset retirement obligation

 

4,048

 

 

 

4,048

 

Deferred income taxes

 

(260,419

)

5,995

 

(254,424

)

Stock compensation

 

13,018

 

 

 

13,018

 

(Gain) loss on derivative instruments

 

32,808

 

 

 

32,808

 

Settlements on derivative instruments

 

8,927

 

 

 

8,927

 

Changes in non-current assets and liabilities

 

2,548

 

 

 

2,548

 

Other, net

 

2,644

 

 

 

2,644

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

(4,327

)

 

 

(4,327

)

Other current assets

 

17,328

 

 

 

17,328

 

Accounts payable and other current liabilities

 

(27,752

)

 

 

(27,752

)

Net cash provided by operating activities

 

213,704

 

 

 

213,704

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(325,058

)

 

 

(325,058

)

Sales of oil and gas assets and other assets

 

12,854

 

 

 

12,854

 

Other capital expenditures

 

(17,774

)

 

 

(17,774

)

Net cash used by investing activities

 

(329,978

)

 

 

(329,978

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Financing and underwriting fees

 

(1

)

 

 

(1

)

Dividends paid

 

(22,655

)

 

 

(22,655

)

Proceeds from exercise of stock options and other

 

1,287

 

 

 

1,287

 

Net cash provided by (used in) financing activities

 

(21,369

)

 

 

(21,369

)

Net change in cash and cash equivalents

 

(137,643

)

 

 

(137,643

)

Cash and cash equivalents at beginning of period

 

779,382

 

 

 

779,382

 

Cash and cash equivalents at end of period

 

$

641,739

 

 

 

$

641,739

 

 

 

Condensed Consolidated Statement of Cash Flows
for the Nine Months Ended
September 30, 2016

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(469,239

)

$

12,653

 

$

(456,586

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

719,142

 

38,528

 

757,670

 

Depreciation, depletion and amortization

 

361,320

 

(58,321

)

302,999

 

Asset retirement obligation

 

6,081

 

 

 

6,081

 

Deferred income taxes

 

(265,508

)

7,140

 

(258,368

)

Stock compensation

 

18,782

 

 

 

18,782

 

(Gain) loss on derivative instruments

 

23,050

 

 

 

23,050

 

Settlements on derivative instruments

 

9,718

 

 

 

9,718

 

Changes in non-current assets and liabilities

 

4,121

 

 

 

4,121

 

Other, net

 

2,931

 

 

 

2,931

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

(1,723

)

 

 

(1,723

)

Other current assets

 

23,034

 

 

 

23,034

 

Accounts payable and other current liabilities

 

(2,378

)

 

 

(2,378

)

Net cash provided by operating activities

 

429,331

 

 

 

429,331

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(485,114

)

 

 

(485,114

)

Sales of oil and gas assets

 

19,013

 

 

 

19,013

 

Sales of other assets

 

5,718

 

 

 

5,718

 

Other capital expenditures

 

(24,013

)

 

 

(24,013

)

Net cash used by investing activities

 

(484,396

)

 

 

(484,396

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Financing and underwriting fees

 

(1

)

 

 

(1

)

Dividends paid

 

(30,243

)

 

 

(30,243

)

Proceeds from exercise of stock options and other

 

4,623

 

 

 

4,623

 

Net cash provided by (used in) financing activities

 

(25,621

)

 

 

(25,621

)

Net change in cash and cash equivalents

 

(80,686

)

 

 

(80,686

)

Cash and cash equivalents at beginning of period

 

779,382

 

 

 

779,382

 

Cash and cash equivalents at end of period

 

$

698,696

 

 

 

$

698,696

 

 

 

Condensed Consolidated Statement of Cash Flows
for the Three Months Ended
March 31, 2015

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(414,941

)

$

(134,629

)

$

(549,570

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

603,599

 

217,585

 

821,184

 

Depreciation, depletion and amortization

 

216,778

 

(7,107

)

209,671

 

Asset retirement obligation

 

1,736

 

 

 

1,736

 

Deferred income taxes

 

(228,739

)

(75,849

)

(304,588

)

Stock compensation

 

5,155

 

 

 

5,155

 

Changes in non-current assets and liabilities

 

1,046

 

 

 

1,046

 

Other, net

 

2,311

 

 

 

2,311

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

72,397

 

 

 

72,397

 

Other current assets

 

9,894

 

 

 

9,894

 

Accounts payable and other current liabilities

 

(156,063

)

 

 

(156,063

)

Net cash provided by operating activities

 

113,173

 

 

 

113,173

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(371,106

)

 

 

(371,106

)

Sales of oil and gas assets and other assets

 

1,180

 

 

 

1,180

 

Other capital expenditures

 

(18,848

)

 

 

(18,848

)

Net cash used by investing activities

 

(388,774

)

 

 

(388,774

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Dividends paid

 

(13,947

)

 

 

(13,947

)

Proceeds from exercise of stock options and other

 

4,618

 

 

 

4,618

 

Net cash provided by (used in) financing activities

 

(9,329

)

 

 

(9,329

)

Net change in cash and cash equivalents

 

(284,930

)

 

 

(284,930

)

Cash and cash equivalents at beginning of period

 

405,862

 

 

 

405,862

 

Cash and cash equivalents at end of period

 

$

         120,932

 

 

 

$

         120,932

 

 

 

Condensed Consolidated Statement of Cash Flows
for the Six Months Ended
June 30, 2015

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(1,015,156

)

$

(124,899

)

$

(1,140,055

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

1,570,886

 

216,315

 

1,787,201

 

Depreciation, depletion and amortization

 

434,229

 

(21,283

)

412,946

 

Asset retirement obligation

 

3,778

 

 

 

3,778

 

Deferred income taxes

 

(570,795

)

(70,133

)

(640,928

)

Stock compensation

 

10,143

 

 

 

10,143

 

Changes in non-current assets and liabilities

 

2,942

 

 

 

2,942

 

Other, net

 

3,276

 

 

 

3,276

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

92,473

 

 

 

92,473

 

Other current assets

 

16,121

 

 

 

16,121

 

Accounts payable and other current liabilities

 

(177,352

)

 

 

(177,352

)

Net cash provided by operating activities

 

370,545

 

 

 

370,545

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(599,222

)

 

 

(599,222

)

Sales of oil and gas assets and other assets

 

9,233

 

 

 

9,233

 

Other capital expenditures

 

(35,882

)

 

 

(35,882

)

Net cash used by investing activities

 

(625,871

)

 

 

(625,871

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Proceeds from sale of common stock

 

752,100

 

 

 

752,100

 

Financing and underwriting fees

 

(22,563

)

 

 

(22,563

)

Dividends paid

 

(28,129

)

 

 

(28,129

)

Proceeds from exercise of stock options and other

 

4,936

 

 

 

4,936

 

Net cash provided by (used in) financing activities

 

706,344

 

 

 

706,344

 

Net change in cash and cash equivalents

 

451,018

 

 

 

451,018

 

Cash and cash equivalents at beginning of period

 

405,862

 

 

 

405,862

 

Cash and cash equivalents at end of period

 

$

856,880

 

 

 

$

856,880

 

 

 

Condensed Consolidated Statement of Cash Flows
for the Nine Months Ended
September 30, 2015

 

(in thousands)

 

As Previously
Reported

 

Corrections

 

As
Corrected

 

Cash flows from operating activities:

 

 

 

 

 

 

 

Net income (loss)

 

$

(1,778,440

)

$

(92,915

)

$

(1,871,355

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

2,751,535

 

180,127

 

2,931,662

 

Depreciation, depletion and amortization

 

619,883

 

(35,039

)

584,844

 

Asset retirement obligation

 

6,393

 

 

 

6,393

 

Deferred income taxes

 

(1,014,264

)

(52,173

)

(1,066,437

)

Stock compensation

 

14,880

 

 

 

14,880

 

(Gain) loss on derivative instruments

 

(1,968

)

 

 

(1,968

)

Settlements on derivative instruments

 

—

 

 

 

—

 

Changes in non-current assets and liabilities

 

16,343

 

 

 

16,343

 

Other, net

 

3,494

 

 

 

3,494

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Receivables, net

 

151,783

 

 

 

151,783

 

Other current assets

 

29,634

 

 

 

29,634

 

Accounts payable and other current liabilities

 

(222,727

)

 

 

(222,727

)

Net cash provided by operating activities

 

576,546

 

 

 

576,546

 

Cash flows from investing activities:

 

 

 

 

 

 

 

Oil and gas expenditures

 

(771,029

)

 

 

(771,029

)

Sales of oil and gas assets

 

38,343

 

 

 

38,343

 

Sales of other assets

 

1,057

 

 

 

1,057

 

Other capital expenditures

 

(58,085

)

 

 

(58,085

)

Net cash used by investing activities

 

(789,714

)

 

 

(789,714

)

Cash flows from financing activities:

 

 

 

 

 

 

 

Proceeds from sale of common stock

 

752,100

 

 

 

752,100

 

Financing and underwriting fees

 

(22,663

)

 

 

(22,663

)

Dividends paid

 

(43,211

)

 

 

(43,211

)

Proceeds from exercise of stock options and other

 

20,392

 

 

 

20,392

 

Net cash provided by (used in) financing activities

 

706,618

 

 

 

706,618

 

Net change in cash and cash equivalents

 

493,450

 

 

 

493,450

 

Cash and cash equivalents at beginning of period

 

405,862

 

 

 

405,862

 

Cash and cash equivalents at end of period

 

$

899,312

 

 

 

$

899,312

 



ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

None.

ITEM 9A.  CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

In connection with the preparation of our Original Filing of the Annual Report on Form 10-K, an evaluation was carried out by

Cimarex’s management, under the supervision and with the participation of the Chief Executive Officer (CEO)(“CEO”) and Chief Financial Officer (CFO)(“CFO”), ofhave evaluated the effectiveness of Cimarex’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)) as of December 31, 2016.  Disclosure2018.  Based on that evaluation, the CEO and CFO concluded that the disclosure controls and procedures are designed to ensureeffective in providing reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods required by the U.S. Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the CEO and CFO, to allow timely decisions regarding required disclosures.

At the time the Original Filing was filed on February 24, 2017, our CEO and CFO concluded that the disclosure controls and procedures were effective as of December 31, 2016. Subsequent to that evaluation, management identified an immaterial error in the full cost ceiling test calculation pursuant to SEC Regulation S-X Rule 4-10 (SAB Topic 12) and as a result amended the December 31, 2016 Form 10-K and recorded an immaterial correction of an error in the historical financial statements.

As a result of this reassessment and the identification of the material weakness described below, our CEO and CFO have, after considering the existence of the material weakness identified, concluded that our disclosure controls and procedures were not effective as of December 31, 2016.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Cimarex’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act).  The company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.  Our internal control over financial reporting also includes those policies and procedures that:

1)             pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets;

2)             provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and

3)             provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

(1)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets;
(2)provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and
(3)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the consolidated financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination

As of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

December 31, 2018, Cimarex’s management assessed the effectiveness of internal control over financial reporting based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in connection with the Original Filing of the Annual Report on Form 10-K on February 24, 2017 and based. Based on that assessment, management concluded that the internal control over financial reporting was effective as of December 31, 2016. In connection with preparation of this Form 10-K/A, our CEO and CFO reassessed the effectiveness of our internal control over financial reporting. Based on this reassessment, our CEO and CFO have concluded that 2018.a material weakness in internal control over financial reporting existed as of December 31, 2016 as described below:

The company did not have an effective process and control to verify the completeness and accuracy of financial information used in the full cost ceiling test calculation in accordance with SEC Regulation S-X  Rule 4-10. The company’s risk assessment process failed to identify necessary modifications to the spreadsheet template when changes in business operations and relevant financial information occurred that impacted the full cost ceiling test calculation.

This resulted in the correction of immaterial misstatements to previously reported impairment expense, depletion expense and income tax expense (benefit) and the related balance sheet accounts as described in Note 1 in the amended consolidated financial statements as of and for the three year period ended December 31, 2016 in this Form 10-K/A. However, these control deficiencies created a reasonable possibility that a material misstatement to our consolidated financial statements would not have been prevented or detected on a timely basis, and therefore we concluded that the deficiencies represented a material weakness in our internal control over financial reporting and that our internal control over financial reporting was not effective as of December 31, 2016.

Our independent registered public accounting firm, KPMG LLP, has audited the effectiveness of our internal control over financial reporting and has issued an adversea report on the effectiveness of our internal control over financial reporting as of December 31, 2016,2018, which is included on page 118 followingfollows this report.

MANAGEMENT’S REMEDIATION PLAN

In response to the material weakness identified in Management’s Report on Internal Control over Financial Reporting, the company has developed a plan with oversight from the Audit Committee of the Board of Directors to remediate the material weakness. The remediation efforts being implemented include the following:

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

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

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

Due to the material weakness referred to above, the company’s management performed additional analyses and procedures in order to conclude that our consolidated financial statements in this Form 10-K/A for the year ended December 31, 2016 are fairly presented, in all material respects, in accordance with accounting principles generally accepted in the United States of America.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Other than the identification of the material weakness described above, there

There was no change in the company’sour internal control over financial reporting that occurred during our most recent fiscal quarter ended December 31, 20162018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.



98

Table of Contents


Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors and Stockholders
Cimarex Energy Co.:

Opinion on Internal Control over Financial Reporting
We have audited Cimarex Energy Co. and subsidiariessubsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2016,2018, based on criteria established in Internal Control –- Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Cimarex Energy Co.Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2018 and subsidiaries’2017, the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2018, and the related notes (collectively, the consolidated financial statements), and our report dated February 20, 2019 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Cimarex Energy Co. and subsidiaries’the Company’s internal control over financial reporting based on our audit.

We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination

KPMG LLP
Denver, Colorado
February 20, 2019

99
Table of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis.  A material weakness related to an ineffective process and control to verify the completeness and accuracy of financial information used in the full cost ceiling test calculation resulting from an ineffective risk assessment process that failed to identify necessary modifications to a spreadsheet template when changes in business operations and relevant financial information occurred has been identified and included in management’s assessment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cimarex Energy Co. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements for each of the years in the three-year period ended December 31, 2016, and this report does not affect our report dated February 24, 2017, except for the immaterial error correction to the consolidated financial statements discussed in Note 1 and the restatement as to the effectiveness of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017, which expressed an unqualified opinion on those consolidated financial statements.

The assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting has been restated by the Company’s management to disclose the aforementioned material weakness and the resultant ineffectiveness of its internal control over financial reporting.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, Cimarex Energy Co. and subsidiaries has not maintained effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

KPMG LLP

Denver, ColoradoContents


February 24, 2017, except for the immaterial error correction to the consolidated financial statements discussed in Note 1 and the restatement as to the effectiveness of internal control over financial reporting for the material weakness related to the full cost ceiling test calculation, as to which the date is May 10, 2017


ITEM 9B.  OTHER INFORMATION
None.


100

None.

Table of Contents



PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning the directors of Cimarex required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 11, 20178, 2019 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2016.2018. The executive officers of Cimarex as of February 24, 201720, 2019 were:

Name

Age

Office

NameAgeOffice
Thomas E. Jorden

59

61

Chairman of the Board, Chief Executive Officer and President

Joseph R. Albi

58

60

Executive Vice President — Operations, Chief Operating Officer

Stephen P. Bell

62

64

Executive Vice President — Business Development

G. Mark Burford

49

51

Vice President and Chief Financial Officer

Francis B. Barron

54

56

Senior Vice President — General Counsel

John A. Lambuth

54

56

Senior Vice President — Exploration

Gary R. Abbott

44

46

Vice President — Corporate Engineering

Krista L. Johnson

46

Vice President — Human Resources, Governmental Relations, and External Affairs

Timothy A. Ficker

49

51

Vice President — Controller, Chief Accounting Officer, and Assistant Secretary

There are no family relationships by blood, marriage, or adoption among any of the above executive officers. All executive officers are elected annually by the board of directors to serve for one year or until a successor is elected and qualified. There is no arrangement or understanding between any of the officers and any other person pursuant to which he or she was selected as an executive officer.

THOMAS E. JORDEN was elected Chairman of the Board effective August 14, 2012 after being named President and Chief Executive Officer effective September 30, 2011. Since December 8, 2003, Mr. Jorden served as Executive Vice President of Exploration and had served in a similar capacity since September 30, 2002. Prior to September 2002, Mr. Jorden was with Key Production Company, Inc., where he served as Vice President of Exploration (October 1999 to September 2002) and Chief Geophysicist (November 1993 to September 1999). Prior to joining Key, Mr. Jorden was with Union Pacific Resources.

JOSEPH R. ALBI was named Executive Vice President and Chief Operating Officer effective September 30, 2011. Mr. Albi served as Executive Vice President of Operations since March 1, 2005. Since December 8, 2003, Mr. Albi served as Senior Vice President of Corporate Engineering. From September 30, 2002 to December 8, 2003, he served as Vice President of Engineering. From June 1994 to September 2002, Mr. Albi was with Key Production Company, Inc. where he served as Vice President of Engineering and Manager of Engineering.

STEPHEN P. BELL was named Executive Vice President, Business Development effective September 13, 2012. Since September 2002, Mr. Bell served as Senior Vice President of Business Development and Land. Prior to its merger with Cimarex, Mr. Bell was with Key Production Company, Inc. since February 1994. In September 1999, he was appointed Senior Vice President, Business Development and Land. From February 1994 to September 1999, he served as Vice President, Land.

G. MARK BURFORDwas named Vice President and Chief Financial Officer in September 2015. He was appointed Vice President, Capital Markets and Planning in December 2010. Mr. Burford joined Cimarex in April 2005 as Director of Capital Markets. Prior to joining Cimarex, he was Director of Investor Relations for Whiting Petroleum and Tom Brown, Inc. His experience also includes equity research with Petrie Parkman & Co., an investment banking firm, and public accounting.

FRANCIS B. BARRON joined Cimarex as Senior Vice President, General Counsel in July 2013. From February 2004 until July 2013, Mr. Barron served in various capacities at Bill Barrett Corporation, a publicly traded, Denver-based oil and gas exploration and development company, including as Executive Vice President, General

Counsel, and Secretary. He also served as Chief Financial Officer from November 2006 until March 2007. Prior to February 2004, Mr. Barron was a partner at the Denver, Colorado office of the law firm of Patton Boggs LLP as well as a partner at Bearman Talesnick & Clowdus Professional Corporation. Mr. Barron’s practice included corporate, securities, and business law for publicly traded oil and gas companies.


101
Table of Contents


JOHN A. LAMBUTH was named Senior Vice President of Exploration in December 2015. Prior to his promotion, he served as the Company’s Vice President of Exploration since September 2012 and Chief Geophysicist, a position he held since joining Cimarex in 2004. Mr. Lambuth began his career in 1985 with Shell Oil Co., where he held various positions in exploration and in research and development. Immediately prior to joining Cimarex, he spent three years as onshore Exploration Manager of El Paso Energy Company.

GARY R. ABBOTT was elected Vice President of Corporate Engineering March 1, 2005. Since January 2002, Mr. Abbott served as manager, Corporate Reservoir Engineering. From April 1999 to January 2002, Mr. Abbott was a reservoir engineer with Key Production Company, Inc.

KRISTA L. JOHNSON joined Cimarex as Vice President of Governmental and External Affairs in November 2014.  Previously she served at Shell Oil Company since 2006, her last role as Vice President, International Organizations.  Prior to joining Shell, she spent eight years with Western Gas Resources, most recently as Director of Government and Media Relations. Her experience also includes private practice in oil and gas law, client based energy advocacy in Washington, work in the Federal Relations Department of the American Petroleum Institute, and in the office of former U.S. Senator Conrad Burns.

TIMOTHY A. FICKER was appointed Vice President, Controller, Chief Accounting Officer, and Assistant Secretary in December 2016 to be effective in February 2017 and previously served as the Company’s Controller since September 2016. From February 2015 until September 2016,Prior to joining Cimarex, he served aswas the Chief Financial Officer and Principal of Alcova Management LLC, a start-up oil and gas exploration and production company concentrating on the Powder River Basin of Wyoming.  Mr. Ficker served as Chief Financial Officer of Venoco, Inc., and in other capacities from March 2007 to November 2014.  From May 2005 to March 2007, he served as Vice President, Chief Financial Officer, Principal Accounting Officer and Secretary of Infinity Energy Resources Inc. Mr. Ficker previously served as an audit partner in KPMG LLP’s energy audit practice in Denver and as an audit partner for Arthur Andersen LLP, where he served clients primarily in the energy industry. His energy clients at KPMG and Arthur Andersen were principally domestic exploration and production companies.


ITEM 11.  EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 11, 20178, 2019 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2016.

2018.


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information


The following table sets forth information with respect to the equity compensation plans available to directors, officers, and employees of the company at December 31, 2018:
Plan Category 
(a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
 
(b)
Weighted-average
exercise price of
outstanding options,
warrants, and rights
 
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities reflected in column (a))
Equity compensation plans approved by security holders 420,332
 $99.01
 908,278
Equity compensation plans not approved by security holders —
 —
 —
Total 420,332
 $99.01
 908,278

     The remaining information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 11, 20178, 2019 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2016.

2018.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 11, 20178, 2019 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2016.

2018.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required under this item is incorporated by reference from the Cimarex Energy Co. definitive Proxy Statement for the May 11, 20178, 2019 Annual Meeting of Shareholders. The Proxy Statement will be filed with the Securities and Exchange Commission no later than 120 days subsequent to December 31, 2016.

2018.

102

Table of Contents


PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Page


Page
(a) (1)


The following financial statements are included in Item 8 to this 10-K:


Consolidated balance sheetsBalance Sheets as of December 31, 20162018 and 20152017

67

64


Consolidated statementsStatements of operationsOperations and comprehensive income (loss)Comprehensive Income (Loss) for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

68

65


Consolidated statementsStatements of cash flowsCash Flows for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

69

66


Consolidated statementsStatements of stockholders’ equityStockholders’ Equity for the years ended December 31, 2016, 2015,2018, 2017, and 20142016

70

67


Notes to consolidated financial statementsConsolidated Financial Statements

71

68

      (2)

(2

)

Financial statement schedules—None

      (3)

(3

)

Exhibits:

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated by reference to a prior SEC filing as indicated.

All management contracts or compensatory plans or arrangements are designated by a plus sign (+).

Exhibit

Title

3.1

ExhibitTitle
2.1
Agreement and Plan of Merger dated as of November 18, 2018, by and among Cimarex Energy Co., CR Sub 1 Inc., CR Sub 2 LLC and Resolute Energy Corporation (filed as Exhibit 2.1 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

3.1
Amended and Restated Certificate of Incorporation of Cimarex Energy Co. (filed as Exhibit 3.1 to Registrant’s Form 8-K (Commission File no.No. 001-31446) dated June 7, 2005 and incorporated herein by reference).

3.2

Amended and Restated By-laws of Cimarex Energy Co. dated December 11, 2013 (filed on December 16, 2013 (Commission File No. 001-31446) and incorporated herein by reference).

3.3

Amended and Restated By-laws of Cimarex Energy Co. dated November 11, 2015 (filed as Exhibits 3.1 and 3.2 to the Current Report on Form 8-K filed on November 12, 2015 (Commission File No. 001-31446) and incorporated herein by reference).

4.1

Specimen Certificate of Cimarex Energy Co. common stock (filed as Exhibit 4.3 to Registration Statement on Form S-3 filed September 17, 2012 (Registration No. 333-183939) and incorporated herein by reference).

4.2

Debt Securities Indenture dated as of April 5, 2012, by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

4.3

First Supplemental Indenture dated as of April 5, 2012, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

4.4

Form of 5.875% Senior Notes due 2022 included in Exhibit 4.34.2 to the Registrant’s Current Report on Form 8-K filed on April 5, 2012 (Commission File No. 001-31446) and incorporated herein by reference.

4.5

Indenture dated as of June 4, 2014, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.


103
Table of Contents


4.6

Exhibit

Title

4.6
First Supplemental Indenture dated as of June 4, 2014, by and among Cimarex Energy Co., the Subsidiary Guarantors party thereto and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

4.7

Form of 4.375% Senior Notes due 2024 included in Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on June 4, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

4.8

4.8
Form of Indenture by and among Cimarex Energy Co. and U.S. Bank National Association, as trustee (filed as Exhibit 4.7 to Registration Statement on Form S-3 filed September 21, 2015 (Registration No. 333-183939) and incorporated herein by reference).

10.1

4.9

Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.
4.10
First Supplemental Indenture dated as of April 10, 2017, by and between Cimarex Energy Co. and U.S. Bank National Association, as trustee included as Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.
4.11
Form of 3.90% Senior Notes due 2027 included in Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on April 10, 2017 (Commission File No. 001-31446) and incorporated herein by reference.
10.1
Credit Agreement dated as of July 14, 2011, among Cimarex, the Administrative Agent, the Co-Syndication Agents, the Co-Documentation Agents and the Lenders filed on July 18, 2011 (Commission File No. 001-31446) as Exhibit 10.l to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.2

First Amendment to Credit Agreement dated as of July 19, 2012, among Cimarex, the Guarantors, the Administrative Agent, and the Lenders filed on May 5, 2014 (Commission File No. 001-31446) as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.3

Second Amendment to Credit Agreement dated as of May 1, 2014, among Cimarex, the Guarantors, the Administrative Agent, and the Lenders filed on May 5, 2014 (Commission File No. 001-31446) as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K and incorporated herein by reference.

10.4

Employment Agreement, dated September 7, 1999, by and between Paul Korus and Key Production Company, Inc. (filed as Exhibit 10.6 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

10.5

Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Paul Korus (filed as Exhibit 10.9 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

10.6

Employment Agreement, dated October 25, 1993, by and between Thomas E. Jorden and Key Production Company, Inc. (filed as Exhibit 10.7 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

+

10.7

10.5

��

Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Thomas E. Jorden (filed as Exhibit 10.11 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.8

10.6

Employment Agreement, dated February 2, 1994, by and between Stephen P. Bell and Key Production Company, Inc. (filed as Exhibit 10.8 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

+

10.9

10.7

Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Stephen P. Bell (filed as Exhibit 10.13 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

+


104
Table of Contents


10.10

ExhibitTitle
10.8
Employment Agreement, dated March 11, 1994, by and between Joseph R. Albi and Key Production Company, Inc. (filed as Exhibit 10.9 to the Registration Statement on Form S-4 dated May 9, 2002 (Registration No. 333-87948) and incorporated herein by reference).

+

10.11

10.9

Amendment to Employment Agreement effective January 1, 2009 between Cimarex Energy Co. and Joseph R. Albi (filed as Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.12

10.10

Amended and Restated 2002 Stock Incentive Plan of Cimarex Energy Co. effective January 1, 2009 (filed as Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001- 31446) and incorporated herein by reference).

+

10.13

10.11

2011 Equity Incentive Plan adopted May 18, 2011 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on March 23, 2011 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.14

10.12
Form of Notice of Grant of Award of Performance Stock and Award Agreement (filed as Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference).

+

10.15

10.13

Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference).

+

10.16

10.14

Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 filed on August 4, 2011 (Commission File no. 001-31446) and incorporated herein by reference).

+

10.17

10.15

Form of Notice of Grant and Award Agreement (Other Stock Award with performance conditions) (filed as Exhibit 10.15 to the Annual Report on Form 10-K for the year ended December 31, 2013 filed on February 26, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.18

10.16

2014 Equity Incentive Plan adopted May 15, 2014 (filed as Appendix A to the Definitive Proxy Statement 14-A filed on April 1, 2014 (Commission File No. 001-31446) and incorporated herein by reference.

+

10.19

10.17

Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed as Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.20

10.18

Form of Notice of Grant of Nonqualified Stock Option and Award Agreement (filed as Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.21

10.19

Form of Notice of Grant of Restricted Stock and Award Agreement (filed as Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.22

10.20

Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award) (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 filed on August 6, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.23

10.21

Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award) (filed as Exhibit 10.23 to the Annual Report on Form 10-K for the year ended December 31, 2014 filed on February 25, 2015 (Commission File No. 001-31446) and incorporated herein by reference).

+

105
Table of Contents


10.24

Exhibit

Title

10.22
Deferred Compensation Plan for Nonemployee Directors adopted May 19, 2004, as amended and restated effective January 1, 2009 (filed as Exhibit 10.18 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.25

10.23

Cimarex Energy Co. Supplemental Savings Plan (amended and restated, effective January 1, 2009) (filed as Exhibit 10.19 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001- 31446) and incorporated herein by reference).

+

10.26

10.24

Cimarex Energy Co. Change in Control Severance Plan dated effective April 1, 2005, amended and restated effective January 1, 2009 (filed as Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2008 filed on February 27, 2009 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.27

10.25
Amendment to Cimarex Energy Co. Change in Control Severance Plan dated effective March 19, 2013 (filed as Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2013 (Commission File No. 001- 31446) and incorporated herein by reference).

+

10.28

10.26

Form of Indemnification Agreement between Cimarex Energy Co. and each of its executive officers and directors (filed as Exhibit 10.20 to the Annual Report on Form 10-K for the year ended December 31, 2012 filed on February 26, 2013 (Commission File No. 001-31446) and incorporated herein by reference).

+

10.29

10.27

Retention Agreement dated June 9, 2010 (filed as Exhibit 10.21 to the Annual Report on Form 10-K for the year ended December 31, 2013 filed on February 26, 2014 (Commission File No. 001-31446) and incorporated herein by reference).

10.30

Credit Agreement Dated as of October 16, 2015, by and among Cimarex, the Administrative Agent, the Syndication Agent, the Documentation Agents, and the Lenders (filed on October 19, 2015 as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).

10.31

10.28

Form of Notice of Grant of Restricted Stock (Director) and Award Agreement (filed as Exhibit 10.2 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 2, 2015 and incorporated herein by reference).

+

10.32

10.29

Succession

Form of Notice of Grant of Restricted Stock (Director) and Award Agreement dated August 17, 2015 (filed as Exhibit 10.210.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 filed on November 4, 2015August 9, 2017 (Commission File No. 001-31446) and incorporated herein by reference).

+

14.1

10.30

Code of Ethics for Chief Executive Officer

Purchase and Senior Financial OfficersSale Agreement dated May 23, 2018 between Cimarex Energy Co., Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. (collectively, as “Seller”) and Callon Petroleum Operating Company as Buyer (filed as Exhibit 14.110.1 to the AnnualRegistrant’s Current Report on Form 10-K for the year ended December 31, 20038-K filed on March 11, 2004May 24, 2018 (Commission File No. 001-31446) and incorporated herein by reference).

14.2

10.31

Form of Notice of Grant of Restricted Stock and Award Agreement (Performance Award). * +
10.32
Amended and Restated Credit Agreement Dated as of February 5, 2019, by and among Cimarex, as Borrower, the Administrative Agent, the Syndication Agent, the Co-Documentation Agents, the Lenders, and the Lead Arrangers and Bookrunners (filed on February 7, 2019 as Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-31446) and incorporated herein by reference).
10.33
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Monarch Alternative Capital LP, MDRA GP LP and Monarch GP LLC (filed as Exhibit 10.1 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).
10.34
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co., John C. Goff and certain other related entities thereto (filed as Exhibit 10.2 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).

106
Table of Contents


ExhibitTitle
10.35
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and RR Advisors, LLC (filed as Exhibit 10.3 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).
10.36
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Richard Betz (filed as Exhibit 10.4 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).
10.37
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Nicholas J. Sutton (filed as Exhibit 10.5 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).
10.38
Voting Agreement, dated as of November 18, 2018, by and among Cimarex Energy Co. and Theodore Gazulis (filed as Exhibit 10.6 to Registrant’s Form 8-K (Commission File No. 001-31446) dated November 20, 2018 and incorporated herein by reference).
14.1
Revised Code of Business Conduct and Ethics for Directors, Officers, and Employees dated August 30, 2016 (filed as Exhibit 14.1 and 14.2 to the Current Report on Form 8-K filed September 1, 2016 (Commission File No. 001-31446) and incorporated herein by reference).

21.1

Subsidiaries

Significant subsidiaries of the Registrant.*

23.1

Consent of KPMG LLP.*

23.2

Consent of DeGolyer and MacNaughton.*

24.1

Power of Attorney of directors of the Registrant.*

31.1

Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2

Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1

Certification of Thomas E. Jorden, Chief Executive Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

32.2

Certification of G. Mark Burford, Chief Financial Officer of Cimarex Energy Co., pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

99.1

99.1
Letter dated January 16, 201721, 2019 from DeGolyer and MacNaughton, independent petroleum engineering consulting firm, reporting the results of its audit of Cimarex reserves as of December 31, 20162018 of certain selected properties.*

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. *


107
Table of Contents


101.PRE

ExhibitTitle
101.PREXBRL Taxonomy Extension Presentation Linkbase Document. *

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document. *


ITEM 16.  FORM 10-K SUMMARY
None.


108

None.

Table of Contents



SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) 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.

Date: May 10, 2017

February 20, 2019

CIMAREX ENERGY CO.

By:

/s/ Thomas E. Jorden

Thomas E. Jorden
Chairman of the Board, Chief Executive Officer, and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

Date

Signature

TitleDate
/s/ Thomas E. Jorden

Chairman of the Board, Director,

Chief Executive Officer,

Thomas E. Jorden

Chief Executive Officer, and President (Principal Executive Officer)

May 10, 2017

February 20, 2019

*

Director, Executive Vice President —

Operations,

Attorney-in-Fact

Operations, Chief Operating Officer

May 10, 2017

February 20, 2019

Joseph R. Albi

/s/ G. Mark Burford

Vice President and Chief

Financial Officer

G. Mark Burford

Financial Officer (Principal(Principal Financial Officer)

May 10, 2017

February 20, 2019

/s/ Timothy A. Ficker

Vice President, Controller, Chief

Accounting Officer

Timothy A. Ficker

Accounting Officer (Principal(Principal Accounting Officer)

May 10, 2017

February 20, 2019

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

Hans Helmerich

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

David A. Hentschel

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

Harold R. Logan, Jr.

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

Floyd R. Price

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

Monroe W. Robertson

*

Attorney-in-Fact

Director

May 10, 2017

*

Attorney-in-FactDirectorFebruary 20, 2019
Lisa A. Stewart

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

Michael J. Sullivan

*

Attorney-in-Fact

Director

May 10, 2017

February 20, 2019

L. Paul Teague

Frances M. Vallejo

*By:

*By:

/s/ G. Mark Burford

Vice President and Chief

Financial Officer

G. Mark Burford
Attorney-in-Fact

Financial Officer (Principal(Principal Financial Officer)

May 10, 2017

February 20, 2019

129



109