10-K 1 xec2017123110k.htm 10-K Document

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(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, 2017
OR
o
TRANSITION 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
 
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 ý 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 o NO ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES ý NO o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ý NO o
Indicate by check mark 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. o
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 ý
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 o NO ý
Aggregate market value of the voting stock held by non-affiliates of Cimarex Energy Co. as of June 30, 2017 was approximately $8.82 billion.
Number of shares of Cimarex Energy Co. common stock outstanding as of January 31, 2018 was 95,438,121.
Documents Incorporated by Reference: Portions of the Registrant’s Proxy Statement for its 2018 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
 



TABLE OF CONTENTS
DESCRIPTION

Item
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


GLOSSARY
Bbl/d—Barrels (of oil or natural gas liquids) per day
Bbls—Barrels (of oil or natural gas liquids)
Bcf—Billion cubic feet
Bcfe—Billion cubic feet equivalent
Btu—British thermal unit
GAAP—Generally accepted accounting principles in the U.S.
Gross Acres or Gross Wells—The total acres or wells, as the case may be, in which a working interest is owned.
MBbls—Thousand barrels
Mcf—Thousand cubic feet (of natural gas)
Mcfe—Thousand cubic feet equivalent
MMBbls—Million barrels
MMBtu—Million British thermal units
MMcf—Million cubic feet
MMcf/d—Million cubic feet per day
MMcfe—Million cubic feet equivalent
MMcfe/d—Million cubic feet equivalent per day
Net Acres or Net Wells—The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
Net Production—Gross production multiplied by net revenue interest
NGL or NGLs—Natural gas liquids
PUD—Proved undeveloped
Tcf—Trillion cubic feet
Tcfe—Trillion cubic feet equivalent
Energy equivalent is determined using the ratio of one barrel of crude oil, condensate, or NGL to six Mcf of natural gas.

3


PART I
 
CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
 
Throughout this Form 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 provide projections of our 2018 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. Forward-looking statements include statements with respect to, among other things:
 
Fluctuations in the price we receive for our oil, gas, and NGL production;
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 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; 
The effectiveness of our internal control over financial reporting; 
Cash flow and anticipated liquidity; 
Amount, nature, and timing of capital expenditures; 
Availability of financing and access to capital markets; 
Administrative, legislative, and regulatory changes; 
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 of acreage; and
Full cost ceiling test impairments to the carrying values of our oil and gas properties. 
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 and timing of development expenditures, and other risks described herein.

4


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.
 
Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-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 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 with the Securities and Exchange Commission, except as required by law.


5


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. Throughout this Form 10-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 grow proved reserves and production for the long-term benefit of our shareholders while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties to reinvest in exploration and development opportunities. 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 in a diversified portfolio of drilling opportunities;
Rate-of-return driven evaluation and ranking of investment decisions;
Tracking predicted versus actual results in a centralized exploration management system, providing feedback to improve results;
Attracting quality employees and maintaining integrated teams of geoscientists, landmen, and engineers; and
Maximizing 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 2013 - 2017.
 
Proved Oil and Gas Reserves
 
Our December 31, 2017 total proved reserves grew 16% from prior year-end. Proved undeveloped reserves as a percentage of total proved reserves decreased to 17% from 21% a year ago. We added 940.7 Bcfe of new reserves through extensions and discoveries. Net negative revisions totaled 59.7 Bcfe, which consisted primarily of a decrease of 248.8 Bcfe for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, offset by an increase of 187.2 Bcfe related to improved commodity prices. The change in our proved reserves is as follows (in Bcfe):
 
Reserves at December 31, 2016
2,890.5

Revisions of previous estimates
(59.7
)
Extensions and discoveries
940.7

Purchases of reserves
1.4

Production
(416.9
)
Sales of reserves
(1.8
)
Reserves at December 31, 2017
3,354.2

 

6


A breakdown by commodity of our proved oil and gas reserves follows:
 
 
December 31,
 
2017
 
2016
 
2015
Proved reserves:
 

 
 

 
 

Gas (Bcf)
1,607.6

 
1,471.4

 
1,517.0

Oil (MMBbls)
137.2

 
105.9

 
107.8

NGL (MMBbls)
153.9

 
130.6

 
124.3

Total (Bcfe)
3,354.2

 
2,890.5

 
2,909.4

Percent developed
83
%
 
79
%
 
75
%
 
At December 31, 2017, 52% of our total proved reserves were located in the Mid-Continent region and 48% were in the Permian Basin. The following table summarizes our estimated proved oil and gas reserves by region as of December 31, 2017.
 
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
 
% of
Total Proved
Reserves
Mid-Continent
1,032,695

 
31,853

 
85,292

 
1,735,565

 
52
%
Permian Basin
573,757

 
105,198

 
68,530

 
1,616,126

 
48
%
Other
1,183

 
187

 
38

 
2,531

 
%
 
1,607,635

 
137,238

 
153,860

 
3,354,222

 
100
%
 
See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 for further information regarding our reserves.
 

7


Production Volumes, Prices, and Costs
 
Our 2017 production volumes totaled 1,142 MMcfe per day, a 19% increase from 2016, and were comprised of 45% gas, 30% oil, and 25% NGLs. The following tables show by region our total and average daily production volumes, 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.
 
 
 
Total Production Volumes
 
Average Daily Production Volumes
 
 
Gas
 
Oil
 
NGL
 
Total
 
Gas
 
Oil
 
NGL
 
Total
Years Ended December 31,
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcfe)
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcfe)
2017
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Permian Basin
 
79,521

 
16,271

 
8,858

 
230,293

 
217.9

 
44.6

 
24.3

 
630.9

Mid-Continent
 
107,463

 
4,547

 
8,503

 
185,761

 
294.4

 
12.5

 
23.3

 
508.9

Other
 
484

 
43

 
13

 
821

 
1.3

 
0.1

 

 
2.3

Total company
 
187,468

 
20,861

 
17,374

 
416,875

 
513.6

 
57.2

 
47.6

 
1,142.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cana area
 
89,471

 
4,168

 
7,813

 
161,354

 
245.1

 
11.4

 
21.4

 
442.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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


8


 
 
Average Realized Price
 
Production Cost (per Mcfe)
Years Ended December 31,
 
Gas
(per Mcf)
 
Oil
(per Bbl)
 
NGL
(per Bbl)
 
2017
 
 

 
 

 
 

 
 

Permian Basin
 
$
2.72

 
$
46.96

 
$
20.25

 
$
0.78

Mid-Continent
 
$
2.78

 
$
47.42

 
$
23.02

 
$
0.43

Other
 
$
2.74

 
$
46.53

 
$
23.11

 
$
1.51

Total Company
 
$
2.76

 
$
47.06

 
$
21.61

 
$
0.63

 
 
 
 
 
 
 
 
 
Cana area
 
$
2.76

 
$
47.44

 
$
23.27

 
$
0.28

 
 
 
 
 
 
 
 
 
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

 
Acquisitions and Divestitures
 
In 2017, we sold interests in various non-core oil and gas properties for cash proceeds of $12 million and made various oil and gas property acquisitions for $8 million.
 
Exploration and Development Overview
 
Cimarex has one reportable segment, exploration and production (“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”) capital is allocated between these two areas.  
regionmap.jpg

9


 
A summary of our 2017 exploration and development activity by region is as follows:
 
 
E&D
Capital
 
Gross
Wells
Completed
 
Net
Wells
Completed
 
%
Completed
As Producers
 
(in millions)
 
 
 
 
 
 
Permian Basin
$
760

 
97

 
55.2

 
98
%
Mid-Continent
500

 
222

 
42.8

 
99
%
Other
21

 

 

 
%
 
$
1,281

 
319

 
98.0

 
98
%
 
The Permian Basin 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 2017, 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 upsized well completions.
 
The Permian Basin produced 630.9 MMcfe per day in 2017, which was 55% of our total company production. Total production from the region increased 25% in 2017 over 2016. In 2017, we invested $760 million, or 59% of our total E&D investment, in the Permian Basin.
 
Our Mid-Continent region consists of Oklahoma and the Texas Panhandle. Our activity in 2017 in the Mid-Continent was focused in the Woodford shale and the Meramec horizon, both in Oklahoma. We continued to implement larger well completions 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.
 
During 2017, production from the Mid-Continent averaged 508.9 MMcfe per day, or 45% of total company production. Total production from the region increased 11% in 2017 over 2016. In 2017, we invested $500 million, or 39% of our total E&D investment, in the Mid-Continent.
 
Drilling Activity
 
In 2017, we completed or participated in the completion of 319 gross (98.0 net) wells, of which we operated 118 gross (77.7 net) wells. At year-end, we were in the process of drilling or participating in 29 gross (13 net) wells and there were 91 gross (33.7 net) wells waiting on completion.
 
We completed the following number of developmental wells in the years indicated in the table below. During these years, we completed no exploratory wells.
 
 
Wells Completed
 
2017
 
2016
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Developmental
 

 
 

 
 

 
 

 
 

 
 

Productive
314

 
96.4

 
153

 
61.0

 
219

 
98.7

Dry
5

 
1.6

 
1

 

 
3

 
1.7

Total
319

 
98.0

 
154

 
61.0

 
222

 
100.4

 

10


At December 31, 2017, we owned an interest in 10,373 gross (3,083 net) productive oil and gas wells. We had working interests in the following number of productive wells by region as of December 31, 2017:
 
 
Gas
 
Oil
 
Gross
 
Net
 
Gross
 
Net
Mid-Continent
3,920

 
1,501

 
698

 
181

Permian Basin
760

 
338

 
4,885

 
1,053

Other
95

 
8

 
15

 
2

 
4,775

 
1,847

 
5,598

 
1,236

 
Significant Properties
 
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 80% of our proved reserves. In 2017, proved reserves in the Cana area of the Watonga-Chickasha field were approximately 46% of Cimarex’s total proved reserves. No other field had 15% or more of our total proved reserves.
 
At December 31, 2017, our ten largest fields by future net revenue discounted at 10% comprised 85% of our total proved reserves. Information regarding each of these fields is as follows:
 
Field
 
Region
 
% of
Total
Proved
Reserves
 
Average
Working
Interest%
 
Approximate
Average Depth
(feet)
 
Primary Formation
Watonga-Chickasha
 
Mid-Continent
 
46.5%
 
26.6%
 
13,000’
 
Woodford
Ford, West
 
Permian Basin
 
12.4%
 
57.7%
 
9,500’
 
Wolfcamp
Grisham
 
Permian Basin
 
8.0%
 
98.3%
 
11,000’
 
Wolfcamp
Dixieland
 
Permian Basin
 
5.9%
 
96.0%
 
11,000’
 
Wolfcamp
Lusk
 
Permian Basin
 
4.2%
 
53.5%
 
8,000’ - 11,000’
 
Bone Spring/Avalon
Cottonwood Draw
 
Permian Basin
 
2.5%
 
62.9%
 
3,000’ - 10,000’
 
Delaware/Wolfcamp
Phantom
 
Permian Basin
 
1.8%
 
39.1%
 
11,500’
 
Bone Spring
Two Georges
 
Permian Basin
 
1.6%
 
90.9%
 
11,500’
 
Bone Spring
Stateline
 
Permian Basin
 
1.4%
 
48.5%
 
7,500’
 
Bone Spring
Quail Ridge
 
Permian Basin
 
1.0%
 
47.0%
 
8,000’ - 13,000’
 
Bone Spring/Morrow
 
 
 
 
85.3%
 
 
 
 
 
 
 

11


Acreage
 
The following table sets forth the gross and net acres of both developed and undeveloped leases held by Cimarex as of December 31, 2017. 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
90,275

 
60,230

 
692,853

 
302,409

 
783,128

 
362,639

Texas
22,845

 
12,101

 
131,119

 
55,796

 
153,964

 
67,897

 
131,351

 
90,522

 
823,972

 
358,205

 
955,323

 
448,727

Permian Basin
 

 
 

 
 

 
 

 
 

 
 

New Mexico
77,297

 
56,796

 
173,756

 
118,355

 
251,053

 
175,151

Texas
79,453

 
56,745

 
210,873

 
148,554

 
290,326

 
205,299

 
156,750

 
113,541

 
384,629

 
266,909

 
541,379

 
380,450

Other
 

 
 

 
 

 
 

 
 

 
 

Arizona
2,097,201

 
2,097,201

 
17,847

 

 
2,115,048

 
2,097,201

California
383,487

 
383,487

 

 

 
383,487

 
383,487

Colorado
40,488

 
18,867

 
41,384

 
1,642

 
81,872

 
20,509

Gulf of Mexico
25,000

 
13,000

 
28,848

 
6,381

 
53,848

 
19,381

Louisiana
12,112

 
9,064

 
2,875

 
168

 
14,987

 
9,232

Michigan
4,702

 
4,624

 
1,183

 
1,183

 
5,885

 
5,807

Montana
31,422

 
7,687

 
7,688

 
1,721

 
39,110

 
9,408

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
10,476

 
3,722

 
27,115

 
6,107

 
37,591

 
9,829

Utah
80,527

 
59,433

 
32,552

 
1,575

 
113,079

 
61,008

Wyoming
96,837

 
13,744

 
43,826

 
4,217

 
140,663

 
17,961

Other
194,359

 
171,191

 
9,772

 
3,499

 
204,131

 
174,690

 
5,624,984

 
5,423,008

 
231,901

 
28,930

 
5,856,885

 
5,451,938

Total
5,913,085

 
5,627,071

 
1,440,502

 
654,044

 
7,353,587

 
6,281,115

 
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
 
2018
 
2019
 
2020
 
2021
 
2022
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Mid-Continent
5,608

 
3,244

 
4,869

 
4,152

 
5,878

 
5,865

 
667

 
667

 
220

 
220

Permian Basin
5,322

 
4,563

 
16,999

 
16,837

 
8,744

 
6,584

 
4,318

 
4,318

 
2,148

 
2,148

Other
31,869

 
31,152

 
64,652

 
60,510

 
34,811

 
34,596

 
7,392

 
7,303

 
29,223

 
28,468

 
42,799

 
38,959

 
86,520

 
81,499

 
49,433

 
47,045

 
12,377

 
12,288

 
31,591

 
30,836

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
% of undeveloped acreage
0.7

 
0.7

 
1.5

 
1.4

 
0.8

 
0.8

 
0.2

 
0.2

 
0.5

 
0.5

 
At December 31, 2017, we had no proved undeveloped reserves scheduled for development beyond the expiration dates of our undeveloped acreage.
 

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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 NGLs to a broad portfolio of customers. Our major customers during 2017 were Energy Transfer Partners, L.P. and Plains All American Pipeline, L.P., which accounted for 21% and 13%, respectively, of our consolidated revenues.
 
If any 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 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.
 
Corporate Headquarters and Employees
 
Our corporate headquarters is located at 1700 Lincoln St., Suite 3700, Denver, Colorado 80203. On December 31, 2017 and 2016, Cimarex had 910 and 856 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 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.
 
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.
 

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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, reviewed reserves associated with greater than 80% of the total future net revenue discounted at 10% attributable to the total interests owned by Cimarex as of December 31, 2017. 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 33 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 23 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 13 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.
 
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”) 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.
 

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Under the Natural Gas Policy Act (“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”), U.S. Environmental Protection Agency (“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 23, 2018.

ITEM 1A.  RISK FACTORS
 
The following risks and uncertainties, together with other information set forth in this Form 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, financial condition, and results of operations, which in turn could negatively impact the value of our securities.
 
Oil, gas, and NGL prices fluctuate due to a number of 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.
 

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If prices decrease, we may 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 and 2015, we recognized ceiling test impairments totaling $757.7 million ($481.4 million, net of tax) and $4.03 billion ($2.56 billion, net of tax), respectively. The impairments resulted primarily from the impact of decreases in the trailing twelve-month average prices for oil, gas, and NGLs utilized in determining the estimated future net cash flows from proved reserves. At December 31, 2017, 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 19% or more in the value of the ceiling limitation would have resulted in an impairment. 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. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income and various components of our balance sheet.
 
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, at December 31, 2016, management concluded that a deficiency in the design of our internal controls related to the full cost ceiling test calculation represented 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, as reported in our Form 10-K/A for that period. We have since remediated this material weakness, however, 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.
 
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.
 

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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 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;
governmental regulation;
access to assets restricted by local government action;
operating costs;
property, severance, excise, and other taxes incidental to oil and gas operations;
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, reviewed our reserve estimates for properties that comprised at least 80% of the discounted future net cash flows before income taxes, using a 10% discount rate, as of December 31, 2017.
 
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 twelve 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 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 with 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, gas, and 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 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.
 

17


Commodity price derivative transactions may limit our potential gains and involve other risks.
 
To limit our exposure to price risk, we enter into derivative agreements from time to time. 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 derivatives.
 
In certain circumstances, derivative transactions may expose us to the risk of financial loss, including instances in which:
 
the counterparties to our derivative agreements fail to perform; 
there is a sudden unexpected event that materially increases oil and gas prices; or 
there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the derivative agreement. 
Because we account for derivative contracts under mark-to-market accounting, during periods we have derivative transactions in place we expect continued volatility in derivative gains and losses on our 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 and the Commodities Futures Trading Commission (“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 derivative 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 derivative 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.
 

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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 and the inability to attract employees to those areas, as well as the vendors’ ability to deploy their resources in easier-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 been 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.
 
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.
 
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. Because 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.
 

19


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”), 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”), 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”), which governs the discharge of pollutants, including natural gas wastes, into federal and state waters; 
The Safe Drinking Water Act (“SDWA”), which governs the disposal of wastewater in underground injection wells; and 
The Clean Air Act (“CAA”) which governs the emission of pollutants into the air.
We believe we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, 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 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”) 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”) 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 gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and 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”), 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”) 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. On 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.

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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”) 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.
 
While hydraulic fracturing historically has been regulated by state oil and 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 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 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 prepared 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”) 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 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 gas that we are ultimately able to produce from our reserves.

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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 gas we produce as well as reductions in availability of capital.
Studies have suggested that emission of certain gases, commonly referred to as greenhouse gases (“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”) 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 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 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 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 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 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.

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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.
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-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 underground 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 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.
 
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 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 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.
 

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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 55% and 45%, respectively, of our oil, gas, and NGL production and approximately 62% and 38%, respectively, of our oil, gas, and NGL revenues for the year ended December 31, 2017. Approximately 48% of our estimated proved reserves were located in the Permian Basin and approximately 52% of our estimated proved reserves were located in the Mid-Continent region as of December 31, 2017.
 
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 oil and 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 wastewater 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 of 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.
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

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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 security and 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-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
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.
 

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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, 2017, other companies operated approximately 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 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.
 
We may not be able to generate enough cash flow to meet our debt obligations.
 
At December 31, 2017, our long-term debt consisted of $750 million of 4.375% senior notes due in 2024 and $750 million of 3.90% senior notes due in 2027. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, capital expenditures, operating expenses, and contractual commitments.
 
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.
 

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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.
 
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 to provide effective contractual protection against all or part of the identified problems.
 

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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 and the amounts spent for those leases will be lost. The combined net acreage expiring in the next three years represents approximately 3.0% of our total net undeveloped acreage at December 31, 2017. At that date, we had leases representing 38,959 net acres expiring in 2018, 81,499 net acres expiring in 2019, and 47,045 net acres expiring in 2020. 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 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 at 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.
 
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 are 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.
 
Certain federal income tax deductions currently available with respect to oil and gas 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, allows for the expensing of capital expenditures, and eliminates the corporate Alternative Minimum Tax. In addition, various proposals have been made recommending the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. While the tax law changes approved in December 2017 did not eliminate any of these incentives, in the future legislation may be introduced in Congress which would implement many of these proposals. These changes include, but are not limited 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.

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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 gas exploration and development, and any such change could have an adverse effect on our financial position, results of operations, and cash flows, including the payment of cash taxes earlier than expected.


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ITEM 1B.  UNRESOLVED STAFF COMMENTS
 
None.

ITEM 3.  LEGAL PROCEEDINGS
 
The information set forth under the heading “Litigation” in Note 10 to the Consolidated Financial Statements included in Part II, Item 8 of this Form 10-K, is incorporated by reference in response to this item.

ITEM 4. MINE SAFETY DISCLOSURES
 
Not applicable.


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PART II
 
ITEM 5.  MARKET FOR 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”) under the symbol XEC. A cash dividend was paid to stockholders in each quarter of 2017. 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 tables set 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.
 
2017
 
High
 
Low
 
Dividends
Declared Per
Share
First Quarter
 
$
144.30

 
$
114.72

 
$
0.08

Second Quarter
 
$
123.92

 
$
91.22

 
$
0.08

Third Quarter
 
$
116.43

 
$
89.49

 
$
0.08

Fourth Quarter
 
$
127.89

 
$
109.55

 
$
0.08

 
2016
 
High
 
Low
 
Dividends
Declared Per
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

 
The closing price of Cimarex stock as reported on the NYSE on January 31, 2018, was $112.20. At January 31, 2018, Cimarex’s 95,438,121 shares of outstanding common stock were held by approximately 1,655 stockholders of record.
 
Equity Compensation Plan 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, 2017:
 
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
 
382,688

 
$
100.17

 
1,991,731

Equity compensation plans not approved by security holders
 

 

 

Total
 
382,688

 
$
100.17

 
1,991,731

 

31


Stock Performance Graph

The following graph compares the cumulative five-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, 2012 to December 31, 2017. The stock price performance included in this graph is not necessarily indicative of future stock price performance.

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-2045688d5d061162a5f.jpg
* $100 invested in 12/31/12 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.
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Cimarex Energy Co.
$
100.00

 
$
182.98

 
$
185.83

 
$
157.57

 
$
240.50

 
$
216.52

S&P 500
$
100.00

 
$
132.39

 
$
150.51

 
$
152.59

 
$
170.84

 
$
208.14

Dow Jones US Exploration & Production
$
100.00

 
$
131.84

 
$
117.64

 
$
89.72

 
$
111.69

 
$
113.14

S&P Oil & Gas Exploration & Production
$
100.00

 
$
127.49

 
$
113.99

 
$
75.06

 
$
99.72

 
$
93.43



32


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,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(in millions, except per share amounts)
Operating results:
 

 
 

 
 

 
 

 
 

Oil, gas, and NGL sales
$
1,874

 
$
1,221

 
$
1,418

 
$
2,373

 
$
1,953

Total revenues (1)
$
1,918

 
$
1,257

 
$
1,453

 
$
2,424

 
$
1,998

Net income (loss) (2)
$
494

 
$
(409
)
 
$
(2,580
)
 
$
526

 
$
462

 
 
 
 
 
 
 
 
 
 
Earnings (loss) per share to common stockholders:
 

 
 

 
 

 
 

 
 

Basic
$
5.19

 
$
(4.38
)
 
$
(27.75
)
 
$
6.01

 
$
5.30

Diluted
$
5.19

 
$
(4.38
)
 
$
(27.75
)
 
$
6.00

 
$
5.29

Cash dividends declared per share
$
0.32

 
$
0.32

 
$
0.64

 
$
0.64

 
$
0.56

 
 
 
 
 
 
 
 
 
 
Cash flow data:
 

 
 

 
 

 
 

 
 

Net cash provided by operating activities (3)
$
1,097

 
$
626

 
$
726

 
$
1,633

 
$
1,334

Net cash used by investing activities
$
(1,266
)
 
$
(692
)
 
$
(1,009
)
 
$
(1,740
)
 
$
(1,531
)
Net cash (used) provided by financing activities (3)
$
(83
)
 
$
(60
)
 
$
656

 
$
508

 
$
132

 
 
December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(in millions, except proved reserves amounts)
Balance sheet data:
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
401

 
$
653

 
$
779

 
$
406

 
$
5

Oil and gas properties, net (2)
$
3,242

 
$
2,354

 
$
2,741

 
$
6,638

 
$
5,669

Goodwill
$
620

 
$
620

 
$
620

 
$
620

 
$
620

Total assets (2) (4)
$
5,043

 
$
4,238

 
$
4,708

 
$
8,443

 
$
6,947

Deferred income tax liability (asset)
$
102

 
$
(56
)
 
$
157

 
$
1,657

 
$
1,351

Long-term obligations:
 

 
 

 
 

 
 

 
 

Long-term debt (principal)
$
1,500

 
$
1,500

 
$
1,500

 
$
1,500

 
$
924

Other
$
206

 
$
184

 
$
197

 
$
194

 
$
164

Stockholders’ equity
$
2,568

 
$
2,043

 
$
2,458

 
$
4,332

 
$
3,834

 
 
 
 
 
 
 
 
 
 
Proved Reserves:
 

 
 

 
 

 
 

 
 

Oil (MBbls)
137,238

 
105,878

 
107,798

 
118,992

 
108,533

Gas (Bcf)
1,608

 
1,471

 
1,517

 
1,667

 
1,294

NGL (MBbls)
153,860

 
130,633

 
124,277

 
125,273

 
92,044

Total (Bcfe)
3,354

 
2,890

 
2,909

 
3,132

 
2,497

________________________________________
(1)
Prior to 2014, our average realized prices 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 to do so.
 
(2)
During 2016, 2015, and 2013, 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), $4.03 billion ($2.56 billion, net of tax), and $190.2 million ($120.8 million, net of tax), respectively.

33


 
(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, 2014, and 2013, we decreased cash outflows for operating activities and cash inflows for financing activities by $26.6 million, $34.2 million, $13.6 million, and $10.1 million, respectively, for the payment of employee tax withholdings on the net settlement of equity-classified awards and for excess tax benefits, as applicable. See Note 6 to the Consolidated Financial Statements for further discussion regarding our adoption of ASU 2016-09.
 
(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 in Item 1A of this report. This discussion also includes forward-looking statements. Refer to CAUTIONARY INFORMATION ABOUT FORWARD-LOOKING STATEMENTS in Part I of this report for important information about these types of statements.
OVERVIEW
 
Cimarex is an independent oil and gas exploration and production company. Our operations are entirely located in the United States, mainly in Oklahoma, Texas, and New Mexico. Currently our operations are focused in two main areas: the Permian Basin and the Mid-Continent. Our Permian Basin region encompasses west Texas and southeast New Mexico. Our Mid-Continent region consists of Oklahoma and the Texas Panhandle.
 
Our principal business objective is to profitably grow proved reserves and production for the long-term benefit of our stockholders through a balanced and abundant drilling inventory while seeking to minimize our impact on the communities in which we operate for the long-term. Our strategy centers on maximizing cash flow from producing properties and profitably reinvesting that cash flow in exploration and development activities. We consider property acquisitions, dispositions, and occasional mergers to enhance our competitive position.
 
We believe that detailed technical analysis, operational focus, and a disciplined capital investment process mitigate risk and position us to continue to achieve profitable increases in proved reserves and production. Our drilling inventory and limited long-term commitments provide the flexibility to respond quickly to industry volatility.
 
Our investments are generally funded with cash flow provided by operating activities together with cash on hand, bank borrowings, sales of non-strategic assets, and occasional public financing based on our monitoring of capital markets and our balance sheet. Conservative use of leverage has long been a part of our financial strategy. We believe that maintaining a strong balance sheet mitigates financial risk and enables us to withstand unpredictable fluctuations in commodity prices.
 
Market Conditions
 
The oil and gas industry is cyclical and commodity prices can fluctuate significantly. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, inventory storage levels, weather conditions, and other factors.
 
Oil prices have improved from early 2016; however, they continue to be volatile and we expect this volatility to persist. During 2017, average NYMEX oil and gas prices were $50.94 per barrel and $3.11 per Mcf, respectively, representing an increase of 18% and 26%, respectively, from the average NYMEX oil and gas prices for 2016. Further, local market prices for oil and gas can be impacted by pipeline capacity constraints limiting takeaway and increasing basis differentials. The Permian Basin and Mid-Continent region gas production growth has resulted in higher differentials and if pipeline constraints remain, higher differentials will persist or potentially worsen.
 

34


Our revenue, profitability, and future growth are highly dependent on the prices we receive for our oil and gas production. Compared to 2016, our realized oil price for 2017 increased 23% to $47.06 per barrel. Similarly, our realized gas price increased 19% to $2.76 per Mcf, while our realized NGL price increased 54% to $21.61 per barrel. See RESULTS OF OPERATIONS Revenues below for further information regarding our realized commodity prices.
 
2017 Summary of Operating and Financial Results
 
The following is a summary of certain 2017 operating and financial results: 
Total daily production volumes increased 19% to 1,142.1 MMcfe per day.
Oil volumes increased 27% to 57.2 MBbls per day.
Gas volumes increased 12% to 513.6 MMcf per day.
NGL volumes increased 23% to 47.6 MBbls per day.
Total production revenue increased 53% to $1.87 billion.
Year-end proved reserves increased to 3.35 Tcfe, as compared to 2.89 Tcfe at year-end 2016.
Exploration and development capital investments were $1.28 billion, as compared to $734.8 million in 2016.
Cash flow provided by operating activities increased 75% to $1.10 billion.
Total debt at December 31, 2017 and 2016 consisted of $1.50 billion of senior notes. During the second quarter 2017, we repaid our 5.875% $750 million notes due 2022 and issued 3.90% $750 million notes due 2027. Our 4.375% $750 million notes are due 2024.
Cash on hand at December 31, 2017 was $400.5 million.
For the year ended December 31, 2017, we had net income of $494.3 million ($5.19 per diluted share), as compared to a net loss of $408.8 million ($4.38 per diluted share) in 2016. Production revenue in 2017 was positively impacted by increased realized commodity prices and production volumes. Lower commodity prices negatively impacted 2016, including resulting in $757.7 million of impairments of our oil and gas properties in that year. Year-over-year changes are discussed further in the RESULTS OF OPERATIONS section that follows.
 
Proved Reserves
 Our proved reserves by region at December 31, 2017 and 2016 were as follows:
 
December 31, 2017
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(MMcfe)
Permian Basin
573,757

 
105,198

 
68,530

 
1,616,126

Mid-Continent
1,032,695

 
31,853

 
85,292

 
1,735,565

Other
1,183

 
187

 
38

 
2,531

Total
1,607,635

 
137,238

 
153,860

 
3,354,222

 
 
December 31, 2016
 
Gas
(MMcf)
 
Oil
(MBbls)
 
NGL
(MBbls)
 
Total
(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

 

35


Year-end 2017 proved reserves increased approximately 16% to 3.35 Tcfe, compared to 2.89 Tcfe at year-end 2016. Proved gas reserves were 1.61 Tcf, proved oil reserves were 0.82 Tcfe, and proved NGL reserves were 0.92 Tcfe. Reserves in our Mid-Continent region accounted for 52% of total proved reserves with nearly all of the remainder in the Permian Basin.
 
During 2017, we added 940.7 Bcfe of new reserves through extensions and discoveries. Net negative revisions totaled 59.7 Bcfe, which consisted primarily of a decrease of 248.8 Bcfe for the removal of PUD reserves whose development will likely be delayed beyond five years of initial disclosure, offset by an increase of 187.2 Bcfe related to improved commodity prices. See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) in Item 8 for a more detailed discussion regarding year-over-year changes in our proved reserves.
 
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 for a discussion of our reserve estimation process and Item 1A RISK FACTORS, which includes a discussion of factors that affect our proved reserves estimates.

RESULTS OF OPERATIONS

2017 Compared to 2016

Revenue
 
Almost all our revenue is derived from sales of our oil, natural gas, and NGL production. Increases or decreases in our revenue, profitability, and future production growth are highly dependent on the commodity prices we receive. Prices are market driven and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality, geopolitical, and economic factors. See Item 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for more information regarding the sensitivity of our revenues to price fluctuations. Realized prices and production volumes were higher in 2017 as compared to 2016, which caused our revenue to increase by $652.8 million, or 53%, from the 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 sale of our Permian Basin oil production is typically tied to the WTI Midland benchmark price and the sale of our Mid-Continent oil production is typically tied to the WTI Cushing benchmark price. During 2017 and 2016, 78% and 80%, respectively, of our oil production was in the Permian Basin and 22% and 20%, respectively, was in the Mid-Continent region. Our realized prices do not include settlements of commodity derivative contracts.
 

36


 
 
Years Ended
December 31,
 
Variance Between
2017 / 2016
 
 
2017