10-K 1 unt-20171231x10k.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                     
Commission file number: 1-9260
image2a01a09.jpg
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
73-1283193
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
8200 South Unit Drive, Tulsa, Oklahoma
74132
(Address of principal executive offices)
(Zip Code)
(Registrant’s telephone number, including area code) (918) 493-7700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, par value $.20 per share
NYSE
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 [x]    No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes [ ]    No [x]
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 [x]    No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [x]    No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ x ]        Accelerated filer [ ]        Non-accelerated filer (Do not check if a smaller reporting company) [  ]
Smaller reporting company [  ]        Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    [ ]     
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes [ ]    No [x]
As of June 30, 2017, the aggregate market value of the voting and non-voting common equity (based on the closing price of the stock on the NYSE on June 30, 2017) held by non-affiliates was approximately $958,140,471. Determination of stock ownership by non-affiliates was made solely for the purpose of this requirement, and the registrant is not bound by these determinations for any other purpose.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
Outstanding at February 13, 2018
Common Stock, $0.20 par value per share
53,061,832 shares
DOCUMENTS INCORPORATED BY REFERENCE
Document
Parts Into Which Incorporated
Portions of the registrant’s definitive proxy statement (the Proxy Statement) with respect to its annual meeting of shareholders scheduled to be held on May 2, 2018. The Proxy Statement will be filed within 120 days after the end of the fiscal year to which this report relates.
Part III
Exhibit Index—See Page 122



FORM 10-K
UNIT CORPORATION

TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
PART I
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 1B.
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
PART II
 
 
 
 
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
 
 
 
PART III
 
 
 
 
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.
 
 
 
 
PART IV
 
 
 
 
Item 15.
Item 16.
 



The following are explanations of some of the terms used in this report.
ARO – Asset retirement obligations.
ASC – FASB Accounting Standards Codification.
ASU – Accounting Standards Update.
Bcf – Billion cubic feet of natural gas.
Bcfe – Billion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
Bbl – Barrel, or 42 U.S. gallons liquid volume.
Boe – Barrel of oil equivalent. Determined using the ratio of six Mcf of natural gas to one barrel of crude oil or NGLs.
BOKF – Bank of Oklahoma Financial Corporation.
Btu – British thermal unit, used in gas volumes. Btu is used to refer to the amount of natural gas required to raise the temperature of one pound of water by one-degree Fahrenheit at one atmospheric pressure.
Development drilling – The drilling of a well within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
DD&A – Depreciation, depletion, and amortization.
FASB – Financial and Accounting Standards Board.
Finding and development costs – Costs associated with acquiring and developing proved natural gas and oil reserves capitalized under generally accepted accounting principles, including any capitalized general and administrative expenses.
Gross acres or gross wells – The total acres or wells in which a working interest is owned.
IF – Inside FERC (U.S. Federal Energy Regulatory Commission).
LIBOR – London Interbank Offered Rate.
MBbls – Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf – Thousand cubic feet of natural gas.
Mcfe – Thousand cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
MMBbls – Million barrels of crude oil or other liquid hydrocarbons.
MMBoe – Million barrels of oil equivalents.
MMBtu – Million Btu’s.
MMcf – Million cubic feet of natural gas.
MMcfe – Million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
Net acres or net wells – The total fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NYMEX – The New York Mercantile Exchange.
Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.


DEFINITIONS — (Continued)

Producing property – A natural gas or oil property with existing production.
Proved developed reserves – Reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate. For additional information, see the SEC’s definition in Rule 4-10(a)(3) of Regulation S-X.
Proved reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations – before the time when the contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For additional information, see the SEC’s definition in Rule 4-10(a)(2)(i) through (iii) of Regulation S-X.
Proved undeveloped reserves – Proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For additional information, see the SEC’s definition in Rule 4-10(a)(4) of Regulation S-X.
Reasonable certainty (regarding reserves) – If deterministic methods are used, reasonable certainty means high confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities recovered will equal or exceed the estimate.
Reliable technology – A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
SARs – Stock appreciation rights.
Unconventional play – Plays targeting tight sand, carbonates, coal bed, or oil and gas shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals, and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require horizontal wells and fracture stimulation treatments or other special recovery processes to produce economically.
Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas or oil regardless of whether the acreage contains proved reserves.
Well spacing – The regulation of the number and location of wells over an oil or gas reservoir, as a conservation measure. Well spacing is normally accomplished by order of the appropriate regulatory conservation commission.
Workovers – Operations on a producing well to restore or increase production.
WTI – West Texas Intermediate, the benchmark crude oil in the United States.



UNIT CORPORATION
Annual Report
For The Year Ended December 31, 2017

PART I

Item 1.     Business

Unless otherwise indicated or required by the context, the terms “Company”, “Unit”, “us”, “our”, “we”, and “its” refer to Unit Corporation or, as appropriate, one or more of its subsidiaries.

Our executive offices are at 8200 South Unit Drive, Tulsa, Oklahoma 74132; our telephone number is (918) 493-7700.

Information regarding our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports, will be provided free in print to any shareholders who request them. They are also available on our internet website at www.unitcorp.com, as soon as reasonably practicable after we electronically file these reports with or furnish them to the Securities and Exchange Commission (SEC). Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F. Street, N.E. Room 1580, N.W., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information about us that we file electronically with the SEC.

In addition, we post on our Internet website, www.unitcorp.com, copies of our corporate governance documents. Our corporate governance guidelines and code of ethics, and the charters of our Board’s Audit, Compensation, and Nominating and Governance Committees, are available for free on our website or in print to any shareholder who requests them. We may occasionally provide important disclosures to investors by posting them in the investor information section of our website, as allowed by SEC rules.

GENERAL

We were founded in 1963 as an oil and natural gas contract drilling company. Today, besides our drilling operations, we have operations in the exploration and production and mid-stream areas. We operate, manage, and analyze our results of operations through our three principal business segments:

Oil and Natural Gas – carried out by our subsidiary Unit Petroleum Company. This segment explores, develops, acquires, and produces oil and natural gas properties for our own account.
Contract Drilling – carried out by our subsidiary Unit Drilling Company. This segment contracts to drill onshore oil and natural gas wells for others and for our own account.
Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes, and treats natural gas for third parties and for our own account.

Each company may conduct operations through subsidiaries of its own.


1


This table provides certain information about us as of February 13, 2018:
Oil and Natural Gas
 
Completed gross wells in which we own an interest
6,375

Contract Drilling
 
Number of drilling rigs available for use
95

Mid-Stream
 
Number of natural gas treatment plants we own
3

Number of processing plants we own
13

Number of natural gas gathering systems we own (1)
22

_________________________ 
(1)    In 2018, two gathering systems were transferred to our oil and natural gas segment.

2017 SEGMENT OPERATIONS HIGHLIGHTS

Oil and Natural Gas
Acquired certain oil and natural gas assets located primarily in Grady and Caddo Counties in western Oklahoma for approximately $54.3 million.
Total year-end 2017 proved oil and natural gas reserves increased 27% over 2016.
Replaced 300% of 2017 production with new reserves.
Sold non-core assets with proceeds of $18.6 million.

Contract Drilling
Utilization cycle during 2017:
Started year with 21 drilling rigs operating;
Placed one new BOSS drilling rig into service at the end of the second quarter;
Returned to service 14 SCR drilling rigs and by mid-July had 36 drilling rigs operating; and
Exited year with 31 drilling rigs operating, following weaker commodity prices in the third quarter and with commodity prices beginning to improve late in the year.
All ten BOSS drilling rigs were operating during the year.

Mid-Stream
Record operating profit (revenue less operating expense) of $51.7 million, a 7% increase over 2016.
Connected five wells to our Pittsburgh Mills gathering system resulting in increased gathered volume of up to 141 MMcf per day.
Began construction on a $14.0 million pipeline and compressor expansion project at our Cashion facility to allow us to gather and process production from a new producer with a significant acreage dedication.
Connected three new wells to our Segno gathering system increasing our gathered volumes to a record high of 98.2 MMcf per day.
Connected six new wells to our Hemphill facility and upgraded compression facilities to handle expected higher volumes in the Buffalo Wallow area.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 16 of our Notes to Consolidated Financial Statements in Item 8 of this report for information regarding each of our segment’s revenues, profits or losses, and total assets.


2


OIL AND NATURAL GAS

General. All our oil and natural gas properties are in the United States. Our producing oil and natural gas properties, unproved properties, and related assets are in these locations:
Division
Location
West division
Western and Southern Texas, Colorado, Wyoming, Montana, North Dakota, New Mexico, Southern Louisiana, and Utah
East division
Eastern Oklahoma and Arkansas
Central division
Western Oklahoma, Texas Panhandle, and Kansas

When we are the operator of a property, we attempt to use a drilling rig owned by our contract drilling segment, and we use our mid-stream segment to gather our gas if it is economical for us to do so.

This table presents certain information regarding our oil and natural gas operations as of December 31, 2017:
Our Divisions/Area
Number
of
Gross
Wells
 
Number
of Net
Wells
 
Number
of Gross
Wells in
Process
 
Number
of Net
Wells in
Process
 
2017 Average
Net Daily Production
 
 
 
 
Natural
Gas
(Mcf)
 
Oil
(Bbls)
 
NGLs (Bbls)
West division
1,163

 
430.75

 

 

 
54,450

 
1,921

 
4,875

East division
192

 
105.00

 

 

 
6,195

 
10

 

Central division
5,109

 
1,905.18

 
10

 
3.11

 
79,792

 
5,508

 
8,104

Total
6,464

 
2,440.93

 
10

 
3.11

 
140,437

 
7,439

 
12,979


As of December 31, 2017, we had no significant water floods, pressure maintenance operations, or any other material related activities that were in process.

Description and Location of Our Core Operations

West division. In our Wilcox play, located primarily in Polk, Tyler, Hardin, and Goliad Counties, Texas, we completed six vertical and two horizontal wells (average working interest 94.3%) in 2017. Seven wells were completed as gas/condensate producers and one well as an oil producer. Annual production from our Wilcox play averaged 91 MMcfe per day (12% oil, 30% NGLs, 58% natural gas) which is a decrease of approximately 4% compared to 2016. We averaged approximately 0.5 Unit drilling rigs operating during 2017 and we plan to use approximately 0.8 Unit drilling rigs operating during 2018. We anticipate completing approximately eight vertical wells and two horizontal wells during 2018. In addition, we plan to complete approximately 13 behind pipe gas and liquids zones.

Central division. In our Southern Oklahoma Hoxbar Oil Trend (SOHOT) play, in western Oklahoma primarily in Grady County, we completed six horizontal oil wells (average working interest 88.8%) in the Marchand zone of the Hoxbar interval. Annual production from western Oklahoma averaged 60.5 MMcfe per day (29% oil, 22% NGLs, 49% natural gas) which is a decrease of approximately 7% compared to 2016. During 2017, we averaged approximately 0.75 Unit drilling rigs operating and we currently plan to use approximately one Unit drilling rigs operating during 2018. We anticipate completing approximately nine horizontal Marchand wells in our SOHOT play during 2018 with six being extended laterals.

Also in Oklahoma, we intend to utilize 0.75 Unit drilling rigs throughout 2018 between our Western STACK and Red Fork plays. We anticipate completing one horizontal Osage, two extended lateral horizontal Meramec, one standard length horizontal Meramec, and two horizontal Red Fork wells.

In our Texas Panhandle Granite Wash play, we completed six extended lateral horizontal gas/condensate wells (average working interest 99%) in our Buffalo Wallow field. Annual production from the Texas Panhandle averaged 86.5 MMcfe per day (10% oil, 38% NGLs, 52% natural gas) which is a decrease of approximately 8% compared to 2016. We used one Unit drilling rig during 2017 and plan to continue using that rig during 2018. We anticipate completing approximately 11 extended lateral Granite Wash horizontal wells in our Buffalo Wallow field during 2018.


3


In our Mississippian play in south central Kansas, we completed one horizontal oil well (working interest 100%). Annual production from Kansas averaged 7.3 MMcfe per day (60% oil, 11% NGLs, 29% natural gas) which is an increase of approximately 18% compared to 2016.

East division. Over the last several years, activity in our East division has been limited due to low gas prices since this area rarely has oil or NGLs associated with the gas. We drilled no wells in this division during 2017.

Dispositions. We had non-core asset sales, net of related expenses, of $18.6 million, $67.2 million, and $1.9 million, in 2017, 2016, and 2015, respectively. Proceeds from these sales reduced the net book value of the full cost pool with no gain or loss recognized.

During prior years, we determined the value of certain of our unproved oil and gas properties were diminished (in part or in whole) based on an impairment evaluation and our anticipated future exploration plans. Those determinations resulted in $114.4 million, $7.6 million, and $10.5 million in 2015, 2016, and 2017, respectively of costs being added to the total of our capitalized costs being amortized. We incurred a $1.6 billion pre-tax ($1.0 billion net of tax) non-cash ceiling test write-down of our oil and natural gas properties in 2015 due to a reduction of the 12-month average commodity prices during the year and including the impaired value of those unproved properties. In 2016, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $161.6 million pre-tax ($100.6 million net of tax) primarily due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We had no ceiling test write-downs for 2017.





4


Well and Leasehold Data. The following tables identify certain information regarding our oil and natural gas exploratory and development drilling operations:
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled:
 
 
 
 
 
 
 
 
 
 
 
Development:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
1

 
1.00

 

 

 
2

 
0.66

East division

 

 

 

 

 

Central division
44

 
9.98

 
9

 
3.57

 
21

 
8.12

Total oil
45

 
10.98

 
9

 
3.57

 
23

 
8.78

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
7

 
6.55

 
4

 
3.98

 
15

 
13.50

East division

 

 

 

 

 

Central division
16

 
7.35

 
7

 
1.12

 
18

 
11.50

Total natural gas
23

 
13.90

 
11

 
5.10

 
33

 
25.00

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division
2

 
0.83

 

 

 
1

 
1.00

East division

 

 

 

 

 

Central division

 

 

 

 
1

 
0.21

Total dry
2

 
0.83

 

 

 
2

 
1.21

Total development
70

 
25.71

 
20

 
8.67

 
58

 
34.99

Exploratory:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 
1

 
1.00

 

 

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total oil

 

 
1

 
1.00

 

 

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 

 

 

 

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total natural gas

 

 

 

 

 

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 

 

 

 

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total dry

 

 

 

 

 

Total exploratory

 

 
1

 
1.00

 

 

Total wells drilled
70

 
25.71

 
21

 
9.67

 
58

 
34.99








5


 
Year Ended December 31,
 
2017
 
2016 (1)
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells producing or capable of producing:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
602

 
124.39

 
648

 
136.59

 
692

 
149.34

East division
11

 

 
18

 
0.72

 
28

 
1.79

Central division
941

 
508.46

 
908

 
497.25

 
907

 
498.75

Total oil
1,554

 
632.85

 
1,574

 
634.56

 
1,627

 
649.88

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
546

 
298.97

 
582

 
296.71

 
659

 
325.57

East division
179

 
104.64

 
181

 
105.85

 
1,358

 
466.22

Central division
4,162

 
1,394.05

 
4,181

 
1,367.87

 
4,217

 
1,376.94

Total natural gas
4,887

 
1,797.66

 
4,944

 
1,770.43

 
6,234

 
2,168.73

Total
6,441

 
2,430.51

 
6,518

 
2,404.99

 
7,861

 
2,818.61

_________________________ 
(1)
During 2016, we had divestitures of 1,300 gross (407.70 net) wells. There were no significant divestitures in 2017 or 2015.

As of February 13, 2018, we were drilling or participating in 12 gross (4.22 net) wells started during 2018.

Cost for development drilling includes $41.6 million, $2.5 million, and $58.6 million in 2017, 2016, and 2015, respectively, to develop previously booked proved undeveloped oil and natural gas reserves.

This table summarizes our leasehold acreage at December 31, 2017: 
 
Year Ended December 31, 2017
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net (1)
 
Gross
 
Net
West division
254,887

 
81,989

 
74,387

 
58,608

 
329,274

 
140,597

East division
88,278

 
23,717

 
3,349

 
2,190

 
91,627

 
25,907

Central division
901,570

 
425,462

 
91,843

 
52,868

 
993,413

 
478,330

Total
1,244,735

 
531,168

 
169,579

 
113,666

 
1,414,314

 
644,834

_________________________ 
(1)
Approximately 70% (West – 76%; East – 95%; and Central – 61%) of the net undeveloped acres are covered by leases that will expire in the years 2018—2020 unless drilling or production extends the terms of those leases. Currently, we do not have any material proved undeveloped (PUD) reserves attributable to acreage where the expiration date precedes the scheduled PUD reserve development plan.




6


Price and Production Data. The following tables identify the average sales price, production volumes, and average production cost per equivalent barrel for our oil, NGLs, and natural gas production for the years indicated:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Average sales price per barrel of oil produced:
 
 
 
 
 
Price before derivatives
$
48.98

 
$
39.05

 
$
45.04

Effect of derivatives
0.46

 
1.45

 
5.75

Price including derivatives
$
49.44

 
$
40.50

 
$
50.79

Average sales price per barrel of NGLs produced:
 
 
 
 
 
Price before derivatives
$
18.35

 
$
11.26

 
$
10.12

Effect of derivatives

 

 

Price including derivatives
$
18.35

 
$
11.26

 
$
10.12

Average sales price per Mcf of natural gas produced:
 
 
 
 
 
Price before derivatives
$
2.49

 
$
1.98

 
$
2.25

Effect of derivatives
(0.03
)
 
0.09

 
0.38

Price including derivatives
$
2.46

 
$
2.07

 
$
2.63






































7


 
Year Ended December 31,
 
2017
 
2016
 
2015
Oil production (MBbls):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
533

 
589

 
422

All other west division fields
168

 
238

 
258

Total west division
701

 
827

 
680

East division
4

 
8

 
11

Central division:
 
 
 
 
 
Buffalo Wallow field
127

 
120

 
145

All other central division fields
1,883

 
2,019

 
2,947

Total central division
2,010

 
2,139

 
3,092

Total oil production
2,715

 
2,974

 
3,783

NGLs production (MBbls):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
1,567

 
1,671

 
1,275

All other west division fields
212

 
216

 
266

Total west division
1,779

 
1,887

 
1,541

East division

 

 
6

Central division:
 
 
 
 
 
Buffalo Wallow field
728

 
592

 
724

All other central division fields
2,230

 
2,535

 
3,003

Total central division
2,958

 
3,127

 
3,727

Total NGLs production
4,737

 
5,014

 
5,274

Natural gas production (MMcf):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
16,799

 
18,145

 
14,538

All other west division fields
3,076

 
2,506

 
3,259

Total west division
19,875

 
20,651

 
17,797

East division
2,261

 
2,956

 
6,846

Central division:
 
 
 
 
 
Buffalo Wallow field
6,228

 
5,506

 
6,895

All other central division fields
22,896

 
26,622

 
34,008

Total central division
29,124

 
32,128

 
40,903

Total natural gas production
51,260

 
55,735

 
65,546

Total production (MBoe):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
4,900

 
5,284

 
4,120

All other west division fields
893

 
872

 
1,067

Total west division
5,793

 
6,156

 
5,187

East division
381

 
500

 
1,158

Central division:
 
 
 
 
 
Buffalo Wallow field
1,893

 
1,629

 
2,019

All other central division fields
7,929

 
8,992

 
11,618

Total central division
9,822

 
10,621

 
13,637

Total production
15,996

 
17,277

 
19,982

Average production cost per equivalent Bbl (1)
$
5.86

 
$
5.62

 
$
7.06

_______________________ 
(1)
Excludes ad valorem taxes and gross production taxes.

8


Our Buffalo Wallow field in Hemphill County, Texas, contained 24%, 13%, 10% of our total proved reserves in 2017, 2016, and 2015, respectively, expressed on an oil equivalent barrels basis. Our Jazz Wilcox field in South Texas, which includes our Gilly, Segno, and Wildwood prospects and several smaller prospects, contained 18%, 26%, and 24% of our total proved reserves for those same years also expressed on an oil equivalent barrels basis. There are no other fields that accounted for more than 15% of our proved reserves.

Oil, NGLs, and Natural Gas Reserves. The following table identifies our estimated proved developed and undeveloped oil, NGLs, and natural gas reserves:
 
Year Ended December 31, 2017
 
Oil
(MBbls)
 
NGLs (MBbls)
 
Natural
Gas
(MMcf)
 
Total
Proved
Reserves
(MBoe)
Proved developed:
 
 
 
 
 
 
 
West division
2,902

 
8,812

 
93,456

 
27,290

East division

 

 
41,720

 
6,953

Central division
11,960

 
24,546

 
253,270

 
78,718

Total proved developed
14,862

 
33,358

 
388,446

 
112,961

Proved undeveloped:
 
 
 
 
 
 
 
West division
329

 
1,220

 
12,255

 
3,592

East division

 

 
1,394

 
232

Central division
4,322

 
10,908

 
106,555

 
32,989

Total proved undeveloped
4,651

 
12,128

 
120,204

 
36,813

Total proved
19,513

 
45,486

 
508,650

 
149,774


Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of those reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in financial disclosures. We use Ryder Scott Company L.P., (Ryder Scott), independent petroleum consultants, to audit the reserves prepared by our reservoir engineers. Ryder Scott has been providing petroleum consulting services throughout the world since 1937. Their summary report is attached as Exhibit 99.1 to this Form 10-K. The wells or locations for which reserve estimates were audited were taken from our reserve and income projections as of December 31, 2017, and comprised 83% of the total proved developed future net income discounted at 10% and 86% of the total proved discounted future net income (based on the SEC's unescalated pricing policy).

Our Reservoir Engineering department is responsible for reserve determination for the wells in which we have an interest. Their primary objective is to estimate the wells' future reserves and future net value to us. Data is incorporated from multiple sources including geological, production engineering, marketing, production, land, and accounting departments. The engineers review this information for accuracy as it is incorporated into the reservoir engineering database. Our internal audit group reviews our internal controls to help provide assurance all the data has been provided. New well reserve estimates are provided to management and the respective operational divisions for additional scrutiny. Major reserve changes on existing wells are reviewed regularly with the operational divisions to confirm completeness and accuracy. As the external audit is being completed by Ryder Scott, the reservoir department performs a final review of all properties for accuracy of forecasting.

Technical Qualifications

Ryder Scott – Mr. Robert J. Paradiso was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott.

Mr. Paradiso, an employee of Ryder Scott since 2008, is a Vice President and serves as Project Coordinator, responsible for coordinating and supervising staff and consulting engineers in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Paradiso served in several engineering positions with Getty Oil Company, Texaco, Union Texas Petroleum, Amax Oil and Gas, Inc., Norcen Explorer, Inc., Amerac Energy Corporation, Halliburton Energy Services, Santa Fe Snyder Corp., and Devon Energy Corporation.

9


Mr. Paradiso earned a Bachelor of Science degree in Petroleum Engineering from Texas Tech University in 1979 and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE).

Besides gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires at least fifteen hours of continuing education annually, including at least one hour in professional ethics, which Mr. Paradiso fulfills. As part of his 2017 continuing education hours, Mr. Paradiso attended 6 hours of formalized training during the 2017 RSC Reserves Conference relating to the definitions and disclosure guidelines in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Paradiso attended an additional 37.5 hours of formalized in-house training during 2017 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and over 38 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Paradiso has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE as of February 19, 2007. For more information regarding Mr. Paradiso’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Company/Employees.

The Company – Responsibility for overseeing the preparation of our reserve report is shared by our reservoir engineers Trenton Mitchell and Derek Smith.

Mr. Mitchell earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1994. He has been an employee of Unit since 2002. Initially, he was the Outside Operated Engineer and since 2003 he has served in the capacity of Reservoir Engineer and in 2010 he was promoted to Manager of Reservoir Engineering. Before joining Unit, he served in several engineering field and technical support positions with Schlumberger Well Services in their pumping services segment (formerly Dowell Schlumberger). He obtained his Professional Engineer registration from the State of Oklahoma in 2004. He has been a member of SPE since 1991 and joined the Society of Petroleum Evaluation Engineers (SPEE) in 2017.

Mr. Smith received a Bachelor of Science in Petroleum Engineering with a Minor in Business from the University of Tulsa in 2005. He worked for Apache Corporation immediately after in Production Engineering, then Reservoir Engineering, followed by Drilling Engineering for approximately one year each before moving to Corporate Reserves in 2008. He joined Unit in 2009 as a Corporate Reserves Engineer involved in reserve evaluation, acquisition appraisals, and prospect reviews with increasing levels of responsibility. He has been a member of SPE since 2000.

As part of their continuing education Mr. Mitchell and Mr. Smith have attended various seminars and forums to enhance their understanding of current standards and issues for reserves presentation. These forums have included those sponsored by various professional societies and professional service firms including Ryder Scott.

Definitions and Other. Proved oil, NGLs, and natural gas reserves, as defined in SEC Rule 4-10(a), are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations – before the time the contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as "proved" includes:

The area identified by drilling and limited by any fluid contacts, and
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas based on available geosciences and engineering data.

Absent data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as incurred in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

10


Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than the reservoir as a whole;
The operation of an installed program in the reservoir or other evidence using reliable technology establishes reasonable certainty of the engineering analysis on which the project or program was based; and
The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average of the prices over the 12-month period before the ending date of the period covered by the report and is an unweighted arithmetic average of the first day of the month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions.

"Proved undeveloped" oil, NGLs, and natural gas reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expense is required for completion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances can estimates for proved undeveloped reserves be attributable to acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless those techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Proved Undeveloped Reserves. As of December 31, 2017, we had 99 gross proved undeveloped wells all of which we plan to develop within five years of initial disclosure at a net estimated cost of approximately $326.2 million. The future estimated development costs to develop our proved undeveloped oil and natural gas reserves for the years 2018-2022, as disclosed in our December 31, 2017 oil and natural gas reserve report, are shown below:
Year
 
Number of Gross Wells Planned
 
Estimated Net Development Cost
(In millions)
2018
 
35

 
$
78.3

2019
 
36

 
152.2

2020
 
19

 
78.3

2021
 
9

 
17.4

2022
 

 

 
 
99

 
$
326.2



11


Our proved undeveloped reserves reported at December 31, 2017 did not include reserves we did not expect to develop within five years of initial disclosure of those reserves. Below is a summary of changes to our proved undeveloped reserves during 2017:
 
Oil
(MMBbls)
 
NGLs
(MMBbls)
 
Natural Gas (Bcf)
 
Total
(MMBoe)
Proved undeveloped reserves, January 1, 2017
3.0

 
6.0

 
58.5

 
18.7

Extensions and discoveries
2.4

 
7.6

 
75.0

 
22.6

Converted to developed
(1.1
)
 
(1.1
)
 
(11.7
)
 
(4.2
)
Revisions of previous estimates
(0.2
)
 
(0.7
)
 
(4.5
)
 
(1.7
)
Purchases of reserves
0.6

 
0.3

 
2.9

 
1.4

Proved undeveloped reserves, December 31, 2017
4.7

 
12.1

 
120.2

 
36.8


During 2017, we converted nine proved undeveloped well locations into proved developed wells at a cost of approximately $41.6 million. The increase in the table above to our extensions and discoveries were due to a number of factors including increased drilling activity, higher commodity prices resulting in an increased budget for future capital expenditures, all contributing to more wells being economic to develop in the next five years.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2017, 2016, and 2015, the changes in quantities, and standardized measure of those reserves for the three years then ended, are shown in the Supplemental Oil and Gas Disclosures in Item 8 of this report.

Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices under arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines and to independent marketing firms under contracts with terms generally ranging from one month to a year. Few of these contracts contain provisions for readjustment of price as most are market sensitive.

Customers. During 2017, sales to Sunoco Logistics accounted for 10% of our oil and natural gas revenues. No other company accounted for over 10% of our oil and natural gas revenues besides our mid-stream segment. During 2017, our mid-stream segment purchased $63.2 million of our natural gas and NGLs production and provided gathering and transportation services of $6.7 million. Intercompany revenue from services and purchases of production between our mid-stream segment and our oil and natural gas segment has been eliminated in our consolidated financial statements. In 2016 and 2015, we eliminated intercompany revenues of $51.9 million and $65.2 million, respectively, attributable to the intercompany purchase of our production of natural gas and NGLs and gathering and transportation services.

CONTRACT DRILLING

General. Our contract drilling business is conducted through Unit Drilling Company. Through this company we drill onshore oil and natural gas wells for our own account and for other oil and natural gas companies. Our drilling operations are in Oklahoma, Texas, Louisiana, Kansas, Colorado, Wyoming, and North Dakota. Until October 31, 2015, our drilling operations in Texas were conducted under Unit Texas Drilling L.L.C., a subsidiary of Unit Drilling Company. Effective October 31, 2015, that subsidiary was merged into Unit Drilling Company.


12


This table identifies certain information about our contract drilling segment:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Number of drilling rigs available for use at year end
95.0

 
94.0

 
94.0

Average number of drilling rigs owned during year
94.5

 
93.9

 
92.6

Average number of drilling rigs utilized
30.0

 
17.4

 
34.7

Utilization rate (1)
32
%
 
19
%
 
38
%
Average revenue per day (2)
$
15,935

 
$
19,154

 
$
20,950

Total footage drilled (feet in 1,000’s)
6,864

 
5,112

 
7,237

Number of wells drilled
468

 
358

 
516

_________________________
(1)
Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs owned during the year.
(2)
Represents the total revenues from our contract drilling segment divided by the total days our drilling rigs were used during the year.

Description and Location of Our Drilling Rigs. An on-shore drilling rig is composed of major equipment components like engines, drawworks or hoists, derrick or mast, substructure, mud pumps, blowout preventers, top drives, and drill pipe. Because of the normal wear and tear from operating 24 hours a day, several of the major components, like engines, mud pumps, top drives, and drill pipe, must be replaced or rebuilt on a periodic basis. Other major components, like the substructure, mast, and drawworks, can be used for extended periods of time with proper maintenance. We also own additional equipment used in operating our drilling rigs, including iron roughnecks, automated catwalks, skidding systems, large air compressors, trucks, and other support equipment. Our drilling rigs can be transferred between divisions.

The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet allowing us to cover a wide range of our customers drilling requirements. In 2017, 36 of our 95 drilling rigs were used in drilling services.

This table shows certain information about our drilling rigs (including their distribution) as of February 13, 2018:
Divisions
Contracted
Rigs
 
Non-Contracted
Rigs
 
Total
Rigs
 
Average
Rated
Drilling
Depth
(ft)
Mid-Continent
25

 
50

 
75

 
17,260

Rocky Mountain
6

 
14

 
20

 
19,925

Totals
31

 
64

 
95

 
17,821


The cyclical nature of the contract drilling business is reflected in drilling rig utilization rates. Drilling rig utilization at the end of 2015 was 26 drilling rigs. Then in 2016, utilization bottomed out in May at 13 operating drilling rigs. As commodity prices improved during the remainder 2016, we exited the year with 21 active drilling rigs. The increased rig activity continued on into 2017 as we added one new BOSS drilling rig and returned to service 14 SCR drilling rigs to peak at 36 drilling rigs utilized in the third quarter. Following which commodity prices weakened during the third quarter and our active drilling rig count dropped to 27 drilling rigs. However, commodity prices rebounded late in the year and we finished 2017 with 31 drilling rigs operating.

Mid-Continent. The Mid-Continent division manages operations from Oklahoma, Texas, Louisiana, and Kansas. The division operated an average of 23.8 drilling rigs during 2017. As of December 31, 2017, this division was operating 26 drilling rigs, 18 of which were working in Oklahoma and the Texas Panhandle, one in East Texas, and seven in the Permian Basin of West Texas.

Rocky Mountains. Our Rocky Mountain division covers Colorado, Utah, Wyoming, Montana, and North Dakota. This vast area has produced several conventional and unconventional oil and gas fields. This division operated an average of 6.2 drilling rigs during 2017. We had two drilling rigs operating in Wyoming and three drilling rigs operating in the Bakken Shale of North Dakota at the end of 2017.


13


The number of drilling rigs we can work depends on several conditions besides demand, including the availability of qualified labor and the availability of needed drilling supplies and equipment. The impact of these conditions affects the utilization for our drilling rigs. Our average utilization rate for 2017, 2016, and 2015 was 32%, 19%, and 38%, respectively.

The following table shows the average number of our drilling rigs working by quarter for the years indicated:
 
2017
 
2016
 
2015
First quarter
25.5

 
20.6

 
50.1

Second quarter
28.8

 
13.5

 
30.7

Third quarter
34.6

 
16.0

 
31.2

Fourth quarter
31.2

 
19.5

 
27.2


Drilling Rig Fleet. The following table summarizes the changes to our drilling rig fleet in 2017. A more complete discussion of changes over the last three years follows the table:
Drilling rigs available for use at January 1, 2017
94

Drilling rigs constructed
1

Total drilling rigs available for use at December 31, 2017
95


Dispositions, Acquisitions, and Construction. During 2015, we recorded a write-down on 31 of our drilling rigs and related equipment of approximately $8.3 million pre-tax based on the estimated market value for similar equipment from auctions sales. We then sold all 31 of these drilling rigs and some other drilling equipment to unaffiliated third parties. The proceeds from the sale of those assets, less costs to sell, was less than the $11.3 million net book value resulting in a loss of $7.3 million pre-tax.

During 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.

During December 2016, we sold an idle 1,500 horsepower SCR drilling rig to an unaffiliated third party. We also built and placed into service for a third party operator our ninth BOSS drilling rig. This new BOSS rig was constructed using the long lead time components purchased in prior years.

During 2017, we built our tenth BOSS drilling rig and placed it into service for a third party operator under a long term contract.

Drilling Contracts. Our drilling contracts are generally obtained through competitive bidding on a well by well basis. Contract terms and payment rates vary depending on the type of contract used, the duration of the work, the equipment and services supplied, and other matters. We pay certain operating expenses, including the wages of our drilling rig personnel, maintenance expenses, and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination by the customer subject to the payment of a fee. Our contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property, and for acts of pollution. The specific terms of these indemnifications are negotiable on a contract by contract basis.

The type of contract used determines our compensation. Contracts are generally one of three types: daywork; footage; or turnkey. Under a daywork contract, we provide the drilling rig with the required personnel and the operator supervises the drilling of the well. Our compensation is based on a negotiated rate to be paid for each day the drilling rig is used. Footage contracts usually require us to bear some of the drilling costs besides providing the drilling rig. We are paid on completion of the well at a negotiated rate for each foot drilled. Under turnkey contracts we drill the well to a specified depth for a set amount and provide most of the required equipment and services. We bear the risk of drilling the well to the contract depth and are paid when the contract provisions are completed. We may incur losses if we underestimate the costs to drill the well or if unforeseen events occur that increase our costs or result in losing the well. We had no footage or turnkey contracts in 2017, 2016, or 2015. Because market demand for our drilling rigs and the desires of our customers determine the types of contracts we use, we cannot predict when and if a part of our drilling will be conducted under footage or turnkey contracts.

The majority of our contracts are on a well-to-well basis, with the rest under term contracts. Term contracts range from six months to two years and the rates can either be fixed throughout the term or allow for periodic adjustments.


14


Customers. During 2017, QEP Resources, Inc. was our largest drilling customer accounting for approximately 26% of our total contract drilling revenues. Our work for this customer was under multiple contracts and our business was not substantially dependent on any of these individual contracts. None of these individual contracts were considered to be material. No other third party customer accounted for 10% or more of our contract drilling revenues.

Our contract drilling segment also provides drilling services for our oil and natural gas segment. During 2017, 2016, and 2015, our contract drilling segment drilled 27, 10, and 38 wells, respectively, for our oil and natural gas segment, or 6%, 3%, and 7%, respectively, of the total wells drilled by our contract drilling segment. Depending on the timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be associated with acquiring an ownership interest in the property. Revenues and expenses for these services are eliminated in our statement of operations, with any profit recognized reducing our investment in our oil and natural gas properties. The contracts for these services are issued under similar terms and rates as the contracts signed with unrelated third parties. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $13.4 million and $22.1 million during 2017 and 2015, respectively, from our contract drilling segment and eliminated the associated operating expense of $11.8 million and $18.3 million during 2017 and 2015, respectively, yielding $1.6 million and $3.8 million during 2017 and 2015, respectively, as a reduction to the carrying value of our oil and natural gas properties. We eliminated no revenue or expenses in our contract drilling segment during 2016.

MID-STREAM

General. Our mid-stream operations are conducted through Superior Pipeline Company, L.L.C. and its subsidiaries. Its operations consist of buying, selling, gathering, processing, and treating natural gas. It operates three natural gas treatment plants, 13 processing plants, 24 active gathering systems, and approximately 1,455 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

This table presents certain information regarding our mid-stream segment for the years indicated:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Gas gathered—Mcf/day
385,209

 
419,217

 
353,771

Gas processed—Mcf/day
137,625

 
155,461

 
182,684

NGLs sold—gallons/day
534,140

 
536,494

 
577,513


Dispositions and Acquisitions. This segment had no significant dispositions or acquisitions during 2015, 2016, or 2017.

Contracts. Our mid-stream segment provides its customers with a full range of gathering, processing, and treating services. These services are usually provided to each customer under long-term contracts (more than one year), but we have some short-term contracts. Our customer agreements include these types of contracts:

Fee-Based Contracts. These contracts provide for a set fee for gathering, transporting, compressing, and treating services. Our mid-stream’s revenue is a function of the volume of natural gas and is not directly dependent on the value of the natural gas. For the year ended December 31, 2017, 71% of our mid-stream segment’s total volumes and 62% of its operating margins (as defined below) were under fee-based contracts.
Commodity-Based Contracts. These contracts consist of several contract structure types. Under these contract structures, our mid-stream segment purchases the raw well-head natural gas and settles with the producer at a stipulated price while retaining all sales proceeds from third parties or retains a negotiated percentage of the sales proceeds from the residue natural gas and NGLs it gathers and processes, with the remainder being paid to the producer. For the year ended December 31, 2017, 29% of our mid-stream segment’s total volumes and 38% of operating margins (as defined below) were under commodity-based contracts.

For each of the above contracts, operating margin is defined as total operating revenues less operating expenses and does not include depreciation, amortization, and impairment, general and administrative expenses, interest expense, or income taxes.

Customers. During 2017, ONEOK, Inc. accounted for approximately 36% of our mid-stream revenues. We believe that if we lost this customer, there are other customers available to purchase our gas and NGLs. During 2017, 2016, and 2015 this segment purchased $63.2 million, $42.7 million, and $57.6 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $6.7 million, $9.2 million, and $7.6 million,

15


respectively. Intercompany revenue from services and purchases of production between this business segment and our oil and natural gas segment has been eliminated in our consolidated financial statements.

VOLATILE NATURE OF OUR BUSINESS

The prevailing prices for oil, NGLs, and natural gas significantly affect our revenues, operating results, cash flow and our ability to grow our operations. Oil, NGLs, and natural gas prices have been volatile and they will probably continue to be so. For each period indicated, this table shows the highest and lowest average prices our oil and natural gas segment received for its sales of oil, NGLs, and natural gas without considering the effect of derivatives:
 
Oil Price per Bbl
 
NGLs Price per Bbl
 
Natural Gas Price per Mcf
Quarter
High
 
Low
 
High
 
Low
 
High
 
Low
2015
 
 
 
 
 
 
 
 
 
 
 
First
$
46.70

 
$
43.22

 
$
18.90

 
$
1.60

 
$
2.85

 
$
2.30

Second
$
54.37

 
$
49.28

 
$
15.41

 
$
10.21

 
$
2.50

 
$
2.11

Third
$
49.02

 
$
40.36

 
$
9.49

 
$
7.81

 
$
2.51

 
$
2.17

Fourth
$
42.21

 
$
33.29

 
$
12.81

 
$
9.03

 
$
2.12

 
$
1.64

2016
 
 
 
 
 
 
 
 
 
 
 
First
$
31.49

 
$
26.62

 
$
9.49

 
$
4.54

 
$
1.86

 
$
1.20

Second
$
45.13

 
$
36.63

 
$
13.19

 
$
8.61

 
$
1.52

 
$
1.36

Third
$
41.75

 
$
41.40

 
$
14.95

 
$
9.87

 
$
2.48

 
$
2.32

Fourth
$
48.80

 
$
42.71

 
$
19.07

 
$
12.14

 
$
2.85

 
$
2.25

2017
 
 
 
 
 
 
 
 
 
 
 
First
$
50.48

 
$
46.85

 
$
20.71

 
$
15.04

 
$
3.76

 
$
2.14

Second
$
48.73

 
$
43.49

 
$
15.33

 
$
14.36

 
$
2.95

 
$
2.30

Third
$
49.66

 
$
44.54

 
$
19.99

 
$
16.17

 
$
2.53

 
$
2.04

Fourth
$
57.38

 
$
49.62

 
$
22.39

 
$
21.13

 
$
2.58

 
$
1.93


Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the actual or perceived supply of and demand for oil and natural gas, market uncertainty, and many additional factors that are beyond our control, including:

political conditions in oil producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries (OPEC) to agree on prices and their ability or willingness to maintain production quotas;
actions taken by foreign oil and natural gas producing nations;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.


16


These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil, NGLs, and natural gas. You are encouraged to read the Risk Factors discussed in Item 1A of this report for additional risks that can affect our operations.

Our contract drilling operations depend on the level of demand in our operating markets. Both short-term and long-term trends in oil, NGLs, and natural gas prices affect demand. Because oil, NGLs, and natural gas prices are volatile, the level of demand for our services can also be volatile.

Our mid-stream operations provide us greater flexibility in delivering our (and third parties) natural gas and NGLs from the wellhead to major natural gas and NGLs pipelines. Margins received for the delivery of these natural gas and NGLs depend on the price for oil, NGLs, and natural gas and the demand for natural gas and NGLs in our area of operations. If the price of NGLs falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to us to extract certain NGLs. The volumes of natural gas and NGLs processed depend highly on the volume and Btu content of the natural gas and NGLs gathered.

COMPETITION

All of our businesses are highly competitive and price sensitive. Competition in the contract drilling business traditionally involves factors such as demand, price, efficiency, condition of equipment, availability of labor and equipment, reputation, and customer relations.

Our oil and natural gas operations likewise encounter strong competition from other oil and natural gas companies. Many competitors have greater financial, technical, and other resources than we do and have more experience than we do in the exploration for and production of oil and natural gas.

Our drilling success and the success of other activities integral to our operations will depend, in part, during times of increased competition on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for these professionals can be intense.

Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, and independent gatherers for the right to purchase natural gas and NGLs, build gathering and processing systems, and deliver the natural gas and NGLs once the gathering and processing systems are established. The principal elements of competition include the rates, terms, and availability of services, reputation, and the flexibility and reliability of service.

OIL AND NATURAL GAS PROGRAMS AND CONFLICTS OF INTEREST

Unit Petroleum Company serves as the general partner of 13 oil and gas limited partnerships (the employee partnerships) which were formed to allow certain of our qualified employees and our directors to participate in Unit Petroleum’s oil and gas exploration and production operations. Employee partnerships were formed for each year beginning with 1984 and ending with 2011. We also had three non-employee partnerships, one formed in 1984 and two formed in 1986 (investments by third parties). Effective December 31, 2014, the 1984 partnership was dissolved and effective December 31, 2016, the two 1986 partnerships were dissolved.

The employee partnerships formed in 1984 through 1999 have been combined into a single consolidated partnership. The employee partnerships each have a set annual percentage (ranging from 1% to 15%) of our interest that the partnership acquires in most of the oil and natural gas wells we drill or acquire for our own account during the year in which the partnership was formed. The total interest the participants have in our oil and natural gas wells by participating in these partnerships does not exceed one percent of our interest in the wells.

Under our partnership agreements, the general partner has broad discretionary authority to manage the business and operations of the partnership, including the authority to decide regarding the partnership’s participation in a drilling location or a property acquisition, the partnership’s expenditure of funds, and distributing funds to partners. Because the business activities of the limited partners and the general partner are different, conflicts of interest will exist and it is impossible to entirely eliminate these conflicts. Additionally, conflicts of interest may arise when we are the operator of an oil and natural gas well and also provide contract drilling services. In these cases, the drilling operations are conducted under drilling contracts containing terms comparable to those contained in our drilling contracts with non-affiliated operators. We believe we fulfill our responsibility to each contracting party and comply fully with the terms of the agreements which regulate these conflicts.

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These partnerships are further described in Notes 2 and 10 to the Consolidated Financial Statements in Item 8 of this report.

EMPLOYEES

As of February 13, 2018, we had approximately 910 employees in our contract drilling segment, 262 employees in our oil and natural gas segment, 124 employees in our mid-stream segment, and 79 in our general corporate area. None of our employees are members of a union or labor organization nor have our operations ever been interrupted by a strike or work stoppage. We consider relations with our employees to be satisfactory.

GOVERNMENTAL REGULATIONS

General. Our business depends on the demand for services from the oil and natural gas exploration and development industry, and therefore our business can be affected by political developments and changes in laws and regulations that control or curtail drilling for oil and natural gas for economic, environmental, or other policy reasons.

Various state and federal regulations affect the production and sale of oil and natural gas. All states in which we conduct activities impose varying restrictions on the drilling, production, transportation, and sale of oil and natural gas. This discussion of certain laws and regulations affecting our operations should not be relied on as an exhaustive review of all regulatory considerations affecting us, due to the multitude of complex federal, state, and local regulations, and their susceptibility to change at any time by later agency actions and court rulings that may affect our operations.

Natural Gas Sales and Transportation. Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (FERC) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. FERC’s jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which FERC continued to regulate the maximum selling prices of certain categories of gas sold in “first sales” in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices for all “first sales” of natural gas. Because “first sales” include typical wellhead sales by producers, all natural gas produced from our natural gas properties is sold at market prices, subject to the terms of any private contracts which may be in effect. FERC’s jurisdiction over interstate natural gas transportation is not affected by the Decontrol Act.

Our sales of natural gas are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are intended by FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of natural gas to the primary role of gas transporters. All natural gas marketing by the pipelines must divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. Because of the various omnibus rulemaking proceedings in the late 1980s and the later individual pipeline restructuring proceedings of the early to mid-1990s, interstate pipelines must provide open and nondiscriminatory transportation and transportation-related services to all producers, natural gas marketing companies, local distribution companies, industrial end users, and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, FERC expanded the impact of open access regulations to certain aspects of intrastate commerce.

FERC has pursued other policy initiatives that affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies; (2) further development of rules governing the relationship of the pipelines with their marketing affiliates; (3) the publication of standards relating to using electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information timely and to enable transactions to occur on a purely electronic basis; (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market; and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services on the pipeline’s demonstration of lack of market control in the relevant service market.

Because of these changes, independent sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and can better conduct business with a larger number of counter parties. These changes generally have improved the access to markets for natural gas while substantially increasing competition in the natural gas marketplace. However, we cannot predict what new or different regulations FERC and other regulatory agencies may adopt or what effect later regulations may have on production and marketing of natural gas from our properties.


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Although in the past Congress has been very active in the area of natural gas regulation as discussed above, the more recent trend has been for deregulation and the promotion of competition in the natural gas industry. In addition to “first sales” deregulation, Congress also repealed incremental pricing requirements and natural gas use restraints previously applicable. There continually are legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. It is impossible to predict what proposals might be enacted by Congress or the various state legislatures and what effect these proposals might have on the production and marketing of natural gas by us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue or what the ultimate effect will be on the production and marketing of natural gas by us cannot be predicted.

Oil and Natural Gas Liquids Sales and Transportation. Our sales of oil and natural gas liquids currently are not regulated and are at market prices. The prices received from the sale of these products are affected by the cost of transporting these products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments could cause decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, FERC examines the relationship between the annual change in the index and the actual cost changes experienced by the oil pipeline industry and makes any necessary adjustment in the index to be used during the ensuing five years. We cannot predict with certainty what effect the periodic review of the index by FERC will have on us.

Exploration and Production Activities. Federal, state, and local agencies also have promulgated extensive rules and regulations applicable to our oil and natural gas exploration, production, and related operations. The states we operate in require permits for drilling operations, drilling bonds, and filing reports about operations and impose other requirements relating to the exploration of oil and natural gas. Many states also have statutes or regulations addressing conservation matters including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, and regulating spacing, plugging and, abandonment of such wells. The statutes and regulations of some states limit the rate at which oil and natural gas is produced from our properties. The federal and state regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are amended or reinterpreted frequently, we cannot predict the future cost or impact of complying with these laws.

Environmental.

General. Our operations are subject to federal, state, and local laws and regulations governing protection of the environment. These laws and regulations may require acquisition of permits before certain of our operations may be commenced and may restrict the types, quantities, and concentrations of various substances that can be released into the environment. Planning and implementation of protective measures must prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids, and other substances may subject us to penalties and cleanup requirements. Handling, storage, and disposal of both hazardous and non-hazardous wastes are subject to regulatory requirements.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, and their state counterparts, are the primary vehicles for imposition of such requirements and for civil, criminal, and administrative penalties and other sanctions for violation of their requirements. In addition, the federal Comprehensive Environmental Response Compensation and Liability Act and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons considered responsible for the release of hazardous substances into the environment. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of remedial action and damages to natural resources.

The EPA in 2015 established publicly owned treatment works (POTWs) effluent guidelines and standards for oil and gas extraction facilities which reflected industry best practices for unconventional oil and gas extraction facilities.

The EPA and the U.S. Army Corp of Engineers (Army) in 2015 proposed a new expansive definition of the “waters of the United States,” which the United States Court of Appeals for the Sixth Circuit stayed nationally. On February 28, 2017, an Executive Order was issued and directed that the EPA and Army consider interpreting the term “navigable waters” in a manner consistent with Justice Scalia’s opinion in Rapanos v. United States (2006). On March 6, 2017, the EPA and Army announced their intention to review and rescind or revise the 2015 Clean Water Rule and on June 27, 2017 they issued a proposed rule and written recommendations. On January 22, 2018, the United States Supreme Court in National Association of Manufacturers v.

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Department of Defense, et al. vacated the Sixth Circuit’s nationwide stay. As a result, on January 31, 2018, the EPA and Army issued a rule providing that the 2015 definition of “waters of the United States” will not apply until two years following the date this rule is published in the Federal Register. In addition, Army includes wetlands within its definition of “waters of the United States.” In 2016, the United States Supreme Court in U.S. Army Corps of Engineers v. Hawkes held that landowners can challenge in court an Army Corps of Engineers jurisdictional determination. It is anticipated this decision will provide landowners an important tool in negotiating and resolving conflicts with federal agencies over the extent of wetlands on a property.

Endangered Species Act. The federal Endangered Species Act, called the “ESA,” and analogous state laws regulate many activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. Designating previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Numerous species have been listed or proposed for protected status in areas in which we provide or could undertake operations. The U.S. Fish and Wildlife Service and the National Marine Fisheries in 2016 issued final revised definitions relating to impacts on critical habitats for potentially endangered species allowing exclusion of certain areas if they will not result in the extinction of the species. In 2017, the Western Governor’s Association issued a Policy Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to make the act more workable and understandable. In December 2017, the Interior Department announced that it is working on possible changes to the ESA with the U.S. Fish and Wildlife Service to revise the regulations for listing endangered and threatened species and for designation of critical habitat. The presence of protected species in areas where we provide contract drilling or mid-stream services or conduct exploration and production operations could impair our ability to timely complete or carry out those services and, consequently, hurt our results of operations and financial position.

Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly called “greenhouse gases,” or GHGs, may be contributing to warming of the Earth’s atmosphere. As a result there have been many regulatory developments, proposals or requirements, and legislative initiatives introduced in the United States (and other parts of the World) that are focused on restricting the emission of carbon dioxide, methane, and other greenhouse gases.

In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act if it represents a health hazard to the public. On December 7, 2009, the U.S. Environmental Protection Agency (EPA) responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of GHGs in the atmosphere threaten the public health and welfare of current and future generations, and that certain GHGs from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of GHG and hence to the threat of climate change. In addition, the EPA issued a final rule, effective in December 2009, requiring the reporting of GHG emissions from specified large (25,000 metric tons or more) GHG emission sources in the U.S., beginning in 2011 for emissions in 2010. During 2010, the EPA proposed revisions to these reporting requirements to apply to all oil and gas production, transmission, processing, and other facilities exceeding certain emission thresholds. On May 12, 2016, the EPA issued three final rules that together will curb emissions of methane, smog-forming volatile organic compounds (VOCs) and toxic air-pollutants such as benzene from new, reconstructed and modified oil and natural gas sources, while providing greater certainty about Clean Air Act permitting requirements for the industry. First, the EPA issued updates to the New Source Performance Standards (NSPS) for the oil and natural gas industry to add requirements that the industry reduce emissions of GHGs and to cover additional equipment and activities in the oil and natural gas distribution chain by setting emissions limits for methane and to require owners/operators to find and repair methane and VOC leaks. Second, the EPA issued a source determination rule regarding the EPA’s air permitting rules as they apply to the oil and natural gas industry. The EPA clarified when multiple pieces of equipment and activities must be deemed a single source for determining whether (i) major source Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review requirements apply regarding preconstruction permitting and (ii) a Title V Operating permit is required. Third, the EPA issued a final rule to implement the Minor New Source Review Program in Indian Country for oil and natural gas production designed to limit emissions of harmful air pollution while making the preconstruction permitting process more streamlined and efficient. These regulations will cause additional costs to reduce emissions of GHGs associated with our operations and could hurt demand for the crude oil we gather, transport, store or otherwise handle in connection with our services. Although the EPA announced in April 2017 it will reconsider the GHG oil and gas emissions rule and delay its compliance, lawsuits have prevented such an effort.

Hydraulic Fracturing. Our oil and natural gas segment routinely applies hydraulic fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the

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Marmaton of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. On July 25, 2017, the Bureau of Land Management announced a proposal to rescind the 2015 Department of Interior final rule on hydraulic fracturing, a rule that was never in effect due to pending litigation. Multiple bills have been introduced in Congress that would (i) block federal regulation of hydraulic fracturing in favor of state rules, (ii) allow a state to regulate hydraulic fracturing on federal lands within that state, (iii) prevent federal regulation of hydraulic regulation to apply to any land held in trust or restricted status for the benefit of Indians without their express consent, (iv) repeal the exemption for hydraulic fracturing in the Safe Drinking Water Act, and/or (v) require the disclosure of chemicals used in hydraulic fracturing. In addition, certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming have adopted, and other states and municipalities and other local governmental entities in some states, have and others are considering adopting regulations and ordinances that could impose more stringent permitting, public disclosure of fracking fluids, waste disposal, and well construction requirements on these operations, and even restrict or ban hydraulic fracturing in certain circumstances.

On December 31, 2016, the EPA released its scientific Final Report on Impacts from Hydraulic Fracturing Activities on Drinking Water. The EPA states the report, which was done at the request of Congress, provides scientific evidence that hydraulic fracturing activities can affect drinking water resources in the United States under some circumstances. The EPA identifies six conditions under which impacts from hydraulic fracturing activities can be more frequent or severe and existing uncertainties and data gaps. Both the EPA and the United States Geological Survey (USGS) have made statements indicating that activities associated with hydraulic fracturing may be causing earthquakes, with the focus being on wastewater disposal wells rather than injection wells. In an August 2015 report sent to the Texas Railroad Commission, the EPA stated it believes there is a significant possibility that North Texas earthquake activity is associated with disposal wells. The USGS has stated that hydraulic fracturing causes small earthquakes, but they are almost always too small to be detected. Regarding disposal wells, the USGS has stated that the injection of wastewater and salt water by deep wells into the subsurface can cause earthquakes that are large enough to be felt and may cause damage. As a result, the USGS and its university partners have deployed seismometers at sites of known or possible injection induced earthquakes in Arkansas, Colorado, Kansas, Oklahoma, Ohio and Texas and that it is also developing methods to assess the earthquake hazard associated with wastewater injection wells.

Any new laws, regulation, or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could delay or limit the drilling services we provide to third parties whose drilling operations could be affected by these regulations or increase our costs of compliance and doing business and delay the development of unconventional gas resources from shale formations which are not commercial without using hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the oil and natural gas we can ultimately produce from our reserves.

Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws, regulations, and/or ordinances could cause increasing our compliance costs or additional operating restrictions and those of our customers. Such future developments also might curtail the demand for fossil fuels which could hurt the demand for our services, which could hurt our future results of operations. Likewise we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation patterns because of climate change (or otherwise) will have a material impact on our operations.

Compliance with applicable environmental requirements has not, to date, had a material effect on the cost of our operations, earnings, or competitive position. However, as noted above in our discussion of the regulation of GHGs and hydraulic fracturing, compliance with amended, new or more stringent requirements of existing environmental regulations or requirements may cause us to incur additional costs or subject us to liabilities that may have a material adverse effect on our results of operations and financial condition.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

Historically, our revenues from our Canadian operations, and information relating to long-lived assets attributable to those operations were immaterial. We no longer have any interests there or any other international operations.


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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENT AND RISK FACTORS

This report contains “forward-looking statements” – meaning, statements related to future events within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included or incorporated by reference in this document which addresses activities, events or developments which we expect or anticipate will or may occur, are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” and similar expressions are used to identify forward-looking statements. This report modifies and supersedes documents filed by us before this report. In addition, certain information we file with the SEC in the future will automatically update and supersede information in this report.

These forward-looking statements include, among others, such things as:

the amount and nature of our future capital expenditures and how we expect to fund our capital expenditures;
prices for oil, NGLs, and natural gas;
demand for oil, NGLs, and natural gas;
our exploration and drilling prospects;
the estimates of our proved oil, NGLs, and natural gas reserves;
oil, NGLs, and natural gas reserve potential;
development and infill drilling potential;
expansion and other development trends of the oil and natural gas industry;
our business strategy;
our plans to maintain or increase production of oil, NGLs, and natural gas;
the number of gathering systems and processing plants we plan to construct or acquire;
volumes and prices for natural gas gathered and processed;
expansion and growth of our business and operations;
demand for our drilling rigs and drilling rig rates;
our belief that the final outcome of our legal proceedings will not materially affect our financial results;
our ability to timely secure third-party services used in completing our wells;
our ability to transport or convey our oil, NGLs, or natural gas production to established pipeline systems;
impact of federal and state legislative and regulatory actions affecting our costs and increasing operating restrictions or delays and other adverse impacts on our business;
our projected production guidelines for the year;
our anticipated capital budgets;
our financial condition and liquidity;
the number of wells our oil and natural gas segment plans to drill during the year; and
our estimates of the amounts of any ceiling test write-downs or other potential asset impairments we may have to record in future periods.

These statements are based on certain assumptions and analyses made by us considering our experience and our perception of historical trends, current conditions, and expected future developments and other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to several risks and uncertainties any one or combination of which could cause our actual results to differ materially from our expectations and predictions, including:

the risk factors discussed in this document and in the documents (if any) we incorporate by reference;

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general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities we pursue;
demand for our land drilling services;
changes in laws or regulations;
changes in the current geopolitical situation;
risks relating to financing, including restrictions in our debt agreements and availability and cost of credit;
risks associated with future weather conditions;
decreases or increases in commodity prices; and
other factors, most of which are beyond our control.

You should not place undue reliance on these forward-looking statements. Except as required by law, we disclaim any intention to update forward-looking information and to release publicly the results of any future revisions we may make to forward-looking statements to reflect events or circumstances after the date of this document to reflect unanticipated events.

To help provide you with a more thorough understanding of the possible effects of these influences on any forward-looking statements made by us, this discussion outlines some (but not all) of the factors that could cause our consolidated results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.

Demand for our contract drilling and mid-stream services depends substantially on the levels of expenditures by the oil and gas industry. A substantial or an extended decline in oil and gas prices could cause lower expenditures by the oil and gas industry, which could have a material adverse effect on our financial condition, results of operations and cash flows. Demand for our contract drilling and mid-stream services depends substantially on the level of expenditures by the oil and gas industry for the exploration, development and production of oil and natural gas reserves. These expenditures depend generally on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and the resulting impact on demand for oil and natural gas. Declines, and anticipated declines, in oil and gas prices could also result in project modifications, delays or cancellations, general business disruptions, and delays in payment of, or nonpayment of, amounts owed to us. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.
The oil and gas industry has historically experienced periodic downturns, which have been characterized by diminished demand for oilfield services and downward pressure on the prices we charge. A significant downturn in the oil and gas industry could cause a reduction in demand for oilfield services and could hurt our financial condition, results of operations and cash flows.

Oil, NGLs, and Natural Gas Prices. Besides the impact oil and gas prices may have on our contract drilling and mid-stream segments, the prices we receive for our oil, NGLs, and natural gas production directly affect our revenues, profitability, and cash flow and our ability to meet our projected financial and operational goals. The prices for oil, NGLs, and natural gas are determined on several factors beyond our control, including:

the demand for and supply of oil, NGLs, and natural gas;
weather conditions in the continental United States (which can greatly influence the demand and prices for natural gas);
the amount and timing of oil, liquid natural gas, and liquefied petroleum gas imports and exports;
the ability of distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas, particularly in times of peak demand which may result because of adverse weather conditions;
the ability or willingness of the OPEC to set and maintain production levels for oil;
oil and gas production levels by non-OPEC countries;
the level of excess production capacity;
political and economic uncertainty and geopolitical activity;
governmental policies and subsidies;

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the costs of exploring for producing and delivering oil and gas; and
technological advances affecting energy consumption.

Oil prices are extremely sensitive to influences domestic and foreign based on political, social or economic underpinnings, any of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of oil, NGLs, and natural gas have been at various times influenced by trading on the commodities markets. That trading has increased the volatility associated with these prices resulting in large differences in prices even on a week-to-week and month-to-month basis. These factors, especially when coupled with much of our product prices being determined daily, can, and do, lead to wide fluctuations in the prices we receive.

Based on our 2017 production, a $0.10 per Mcf change in what we receive for our natural gas production, without the effect of derivatives, would cause a corresponding $410,000 per month ($4.9 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $217,000 per month ($2.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs price, without the effect of derivatives, would have a $380,000 per month ($4.6 million annualized) change in our pre-tax operating cash flow.

To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter into derivative contracts such as swaps and collars. To date, we have derivatives covering part, but not all of our production which provides price protection only against declines in oil, NGLs, and natural gas prices on the production subject to our derivatives, but not otherwise. Should market prices for the production we have derivatives exceed the prices due under our derivative contracts, our derivative contracts then expose us to risk of financial loss and limit the benefit to us of those increases in market prices. During 2017, all of our NGLs volumes, half of our oil, and about a quarter of our natural gas volumes were sold at market responsive prices. To help manage our cash flow and capital expenditure requirements, we had derivative contracts on approximately 50% and 72% of our 2017 average daily production for oil and natural gas, respectively. A more thorough discussion of our derivative arrangements is contained in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report in Item 7.

Uncertainty of Oil, NGLs, and Natural Gas Reserves; Ceiling Test. Many uncertainties are inherent in estimating quantities of oil, NGLs, and natural gas reserves and their values, including many factors beyond our control. The oil, NGLs, and natural gas reserve information in this report represents only an estimate of these reserves. Oil, NGLs, and natural gas reservoir engineering is a subjective and an inexact process of estimating underground accumulations of oil, NGLs, and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs, and natural gas reserves depend on several variable factors, including historical production from the area compared with production from other producing areas, and assumptions about:

reservoir size;
the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
future operating costs;
severance and excise taxes;
operational risks;
development costs; and
workover and remedial costs.

Some or all of these assumptions may vary considerably from actual results. For these and other reasons, estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those oil, NGLs, and natural gas reserves based on risk of recovery, and estimates of the future net cash flows from oil, NGLs, and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues, and expenditures regarding our oil, NGLs, and natural gas reserves will likely vary from estimates and those variances may be material.


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The information regarding discounted future net cash flows in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. Using full cost accounting requires us to use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by these factors:

the amount and timing of oil, NGLs, and natural gas production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.

In addition, the 10% discount factor, required by the SEC for calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and the risks associated with our operations or the oil and natural gas industry.

We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from those proved reserves, discounted at 10%. Application of this “ceiling test” generally requires pricing future revenue at the unescalated 12-month average price and requires a write-down for accounting purposes if we exceed the ceiling. We may be required to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would cause a charge to earnings but would not impact our cash flow from operating activities. Once incurred, a write-down is not reversible.

Debt and Bank Borrowing. We have incurred and expect to continue to incur substantial capital expenditures in our operations. Historically, we have funded our capital needs through a combination of internally generated cash flow and borrowings under our bank credit agreement. In 2011 and 2012, we issued $250.0 million (the 2011 Notes) and $400.0 million (the 2012 Notes), respectively, of senior subordinated notes (collectively, the Notes). We have, and will continue to have, a certain amount of indebtedness. At December 31, 2017, we had $178.0 million of outstanding long-term debt under our credit agreement, and $642.3 million, net of unamortized discount and debt issuance costs, under the Notes.

Depending on our debt, the cash flow needed to satisfy that debt and the covenants in our bank credit agreement and those applicable to the Notes could:

limit funds otherwise available for financing our capital expenditures, our drilling program or other activities or cause us to curtail these activities;
limit our flexibility in planning for or reacting to changes in our business;
place us at a competitive disadvantage to those of our competitors that are less indebted than we are;
make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if a downturn in our business occurs; and
prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or any future credit facilities.

Our ability to meet our debt obligations depends on our future performance. If the requirements of our indebtedness are not satisfied, a default could be deemed to occur and our lenders or the holders of the Notes could accelerate the payment of the outstanding indebtedness. If that were to happen, we would not have sufficient funds available (and probably could not obtain the financing required) to meet our obligations.

Our existing debt, and our future debt, if any, is, largely, based on the costs associated with the projects we undertake and of our cash flow. Generally, our normal operating costs are those resulting from the drilling of oil and natural gas wells, the acquisition of producing properties, the costs associated with the maintenance, upgrade, or expansion of our drilling rig fleet, and the operations of our natural gas buying, selling, gathering, processing, and treating systems. To some extent, these costs, particularly the first two, are discretionary and we maintain some control regarding the timing or the need to incur them. But, sometimes, unforeseen circumstances may arise, like an unanticipated opportunity to make a large acquisition or the need to

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replace a costly drilling rig component due to an unexpected loss, which could force us to incur additional debt above what we had expected or forecasted. Likewise, if our cash flow should prove insufficient to cover our cash requirements we would need to increase our debt either through bank borrowings or otherwise.

RISK FACTORS

Many other factors could hurt our business. This discussion describes the material risks currently known to us. However, additional risks we do not know about or that we currently view as immaterial may also impair our business or hurt the value of our securities. You should carefully consider the risks described below together with the other information contained in, or incorporated by reference into, this report.

If demand for oil, NGLs, and natural gas is reduced, our ability to market and produce our oil, NGLs, and natural gas may be negatively affected.

Historically, oil, NGLs, and natural gas prices have been volatile, with significant increases and significant price drops being experienced occasionally. Various factors beyond our control will have a significant effect on oil, NGLs, and natural gas prices. Those factors include, among other things, the domestic and foreign supply of oil, NGLs, and natural gas, the price of imports, the levels of consumer demand, the price and availability of alternative fuels, the availability of pipeline capacity, and changes in existing and proposed federal regulation and price controls.

The oil, NGLs, and natural gas markets are also unsettled due to several factors. Production from oil and natural gas wells in some geographic areas of the United States has been curtailed for considerable periods of time due to a lack of market demand and transportation and storage capacity. It is possible, however, that some of our wells may be shut-in or that oil, NGLs, and natural gas will be sold on terms less favorable than might otherwise be obtained should demand for oil, NGLs, and natural gas decrease. Competition for markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. Oil, NGLs, and natural gas surpluses could cause our inability to market oil, NGLs, and natural gas profitably, causing us to curtail production and/or receive lower prices for our oil, NGLs, and natural gas, situations which would hurt us.

Disruptions in the financial markets could affect our ability to obtain financing or refinance existing indebtedness on reasonable terms and may have other adverse effects.

Commercial-credit and equity market disruptions may cause tight capital markets in the United States. Liquidity in the global-capital markets can be severely contracted by market disruptions making terms for certain financings less attractive, and in certain cases, result in the unavailability of certain types of financing. Because credit and equity market turmoil, we may not be able to obtain debt or equity financing, or refinance existing indebtedness on favorable terms, which could affect operations and financial performance.

Oil, NGLs, and natural gas prices are volatile, and low prices have negatively affected our financial results and could do so in the future.

Our revenues, operating results, cash flow, and growth depend substantially on prevailing prices for oil, NGLs, and natural gas. Historically, oil, NGLs, and natural gas prices and markets have been volatile, and they are likely to continue to be volatile. Any decline in prices would have a negative impact on our future financial results and our ability to grow our business segments.

Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the actual or perceived supply of and demand for oil, NGLs, and natural gas, market uncertainty, and many additional factors that are beyond our control. These factors include:

political conditions in oil producing regions;
the ability of the members of the OPEC to agree on prices and their ability or willingness to maintain production quotas;
actions taken by foreign oil and natural gas companies;
the price of foreign oil imports;
imports and exports of oil and liquefied natural gas;

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actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
United States storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil, NGLs, and natural gas.

Our contract drilling operations depend on levels of activity in the oil, NGLs, and natural gas exploration and production industry.

Our contract drilling operations depend on the level of activity in oil, NGLs, and natural gas exploration and production in our operating markets. Both short-term and long-term trends in oil, NGLs, and natural gas prices affect the level of that activity. Because oil, NGLs, and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Any decrease from current oil, NGLs, and natural gas prices could further depress the level of exploration and production activity. This, in turn, would likely result in further declines in the demand for our drilling services and would have an adverse effect on our contract drilling revenues, cash flows, and profitability. As a result, the future demand for our drilling services is uncertain.

The industries in which we operate are highly competitive, and many of our competitors have resources greater than we do.

The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded based on competitive bids, which may cause intense price competition. Some of our competitors in the contract drilling industry have greater financial and human resources than we do. These resources may enable them to better withstand periods of low drilling rig utilization, to compete more effectively based on price and technology, to build new drilling rigs or acquire existing drilling rigs, and to provide drilling rigs more quickly than we do in periods of high drilling rig utilization.

The oil and natural gas industry is also highly competitive. We compete in the areas of property acquisitions and oil and natural gas exploration, development, production, and marketing with major oil companies, other independent oil and natural gas concerns, and individual producers and operators. In addition, we must compete with major and independent oil and natural gas concerns in recruiting and retaining qualified employees. Many of our competitors in the oil and natural gas industry have resources substantially greater than we do.

The mid-stream industry is also highly competitive. We compete in areas of gathering, processing, transporting, and treating natural gas with other mid-stream companies. We are continually competing with larger mid-stream companies for acquisitions and construction projects. Many of our competitors have greater financial resources, human resources, and geographic presence larger than we do.

Growth through acquisitions is not assured.

We have experienced growth in each segment, in part, through mergers and acquisitions. The contract land drilling industry, the exploration and development industry, and the gas gathering and processing industry, have experienced significant consolidation over the past several years, and there can be no assurance that acquisition opportunities will be available. Even if available, there is no assurance we would have the financial ability to pursue the opportunity. And we are likely to continue to face intense competition from other companies for acquisition opportunities.


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There can be no assurance we will:

be able to identify suitable acquisition opportunities;
have sufficient capital resources to complete additional acquisitions;
successfully integrate acquired operations and assets;
effectively manage the growth and increased size;
maintain the crews and market share to operate any future drilling rigs we may acquire; or
improve our financial condition, results of operations, business or prospects in any material manner because of any completed acquisition.

We may incur substantial indebtedness to finance future acquisitions and also may issue debt instruments, equity securities, or convertible securities in connection with any acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and issuing additional equity would be dilutive to existing shareholders. Also, continued growth could strain our management, operations, employees, and other resources.

Successful acquisitions, particularly those of oil and natural gas companies or of oil and natural gas properties, require an assessment of several factors, many of which are beyond our control. These factors include recoverable reserves, exploration potential, future oil, NGLs, and natural gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain.

Our operations have significant capital requirements, and our indebtedness could have important consequences.

We have experienced and will continue to experience substantial capital needs for our operations. We have $642.3 million of indebtedness outstanding (net of unamortized discount and debt issuance costs) under the senior subordinated notes we have issued to date and, in addition, may borrow up to $475.0 million under our credit agreement. As of February 13, 2018, we had $173.8 million outstanding borrowings under our credit agreement. Our level of indebtedness, the cash flow to satisfy our indebtedness, and the covenants governing our indebtedness could:

limit funds available for financing capital expenditures, our drilling program or other activities or cause us to curtail these activities;
limit our flexibility in planning for, or reacting to changes in, our business;
place us at a competitive disadvantage to some of our competitors that are less leveraged than we are;
make us more vulnerable during periods of low oil, NGLs, and natural gas prices or if downturn in our business occurs; and
prevent us from obtaining additional financing on acceptable terms or limit amounts available under our existing or any future credit facilities.

Our ability to meet our debt service and other contractual and contingent obligations will depend on our future performance. In addition, lower oil, NGLs, and natural gas prices could cause future reductions in the amount available for borrowing under our credit agreement, reducing our liquidity, and even triggering mandatory loan repayments.

The instruments governing our indebtedness contain various covenants limiting the conduct of our business.

The indentures governing our senior subordinated notes and our credit agreement contain various restrictive covenants that limit the conduct of our business. These agreements place certain limits on our ability to, among other things:

incur additional indebtedness, guarantee obligations or issue disqualified capital stock;
pay dividends or distributions on our capital stock or redeem, repurchase or retire our capital stock;
make investments or other restricted payments;
grant liens on assets;
enter into transactions with stockholders or affiliates;

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sell assets;
issue or sell capital stock of certain subsidiaries; and
merge or consolidate.

In addition, our credit agreement also requires us to maintain a minimum current ratio and a maximum senior indebtedness or leverage ratio.

If we violate the restrictions in the indentures governing our senior subordinated notes, our credit agreement or any other subsequent financing agreements, a default may allow the creditors, if the agreements so provide, to accelerate the related indebtedness and any other indebtedness to which a cross-acceleration or cross-default provision applies. If that occurs, we may not make the required payments or borrow sufficient funds to refinance that debt. Even if new financing were available at that time, it may not be on terms acceptable to us. In addition, lenders may be able to terminate any commitments they had made to make available further funds.

Our future performance depends on our ability to find or acquire additional oil, NGLs, and natural gas reserves that are economically recoverable.

Production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we replace the reserves we produce, our reserves will decline, resulting eventually in a decrease in oil, NGLs, and natural gas production and lower revenues and cash flow from operations. Historically, we have increased reserves after taking production into account through exploration and development. We have conducted these activities on our existing oil and natural gas properties and on newly acquired properties. We may not continue to replace reserves from these activities at acceptable costs. Lower prices of oil, NGLs, and natural gas may further limit the reserves that can economically be developed. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including acquisitions significantly larger than those consummated by us. We cannot assure you we will successfully consummate any acquisition, that we can acquire producing oil and natural gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.

The competition for producing oil and natural gas properties is intense. This competition could mean that to acquire properties we must pay higher prices and accept greater ownership risks than we have in the past.

Our exploration and production and mid-stream operations involve high business and financial risk which could hurt us.

Exploration and development involve numerous risks that may cause dry holes, the failure to produce oil, NGLs, and natural gas in commercial quantities and the inability to fully produce discovered reserves. The cost of drilling, completing, and operating wells is substantial and uncertain. Numerous factors beyond our control may cause the curtailment, delay, or cancellation of drilling operations, including:

unexpected drilling conditions;
pressure or irregularities in formations;
capacity of pipeline systems;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs, pressure pumping services, or delivery crews and the delivery of equipment.

Exploratory drilling is a speculative activity. Although we may disclose our overall drilling success rate, those rates may decline. Although we may discuss drilling prospects we have identified or budgeted for, we may ultimately not lease or drill these prospects within the expected time frame, or at all. Lack of drilling success will have an adverse effect on our future results of operations and financial condition.


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Our mid-stream operations involve numerous risks, both financial and operational. The cost of developing gathering systems and processing plants is substantial and our ability to recoup these costs is uncertain. Our operations may be curtailed, delayed, or canceled because of many things beyond our control, including:

unexpected changes in the deliverability of natural gas reserves from the wells connected to the gathering systems;
availability of competing pipelines in the area;
capacity of pipeline systems;
equipment failures or accidents;
adverse weather conditions;
compliance with governmental requirements;
delays in developing other producing properties within the gathering system’s area of operation; and
demand for natural gas and its constituents.

Many of the wells from which we gather and process natural gas are operated by other parties. We have little control over the operations of those wells which can act to increase our risk. Operators of those wells may act in ways not in our best interests.

Competition for experienced technical personnel may negatively affect our operations or financial results.

The success of our three segments and the success of our other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, and other professionals. Competition for these professionals can be intense, particularly when the industry is experiencing favorable conditions.

Our derivative arrangements might limit the benefit of increases in oil, NGLs, and natural gas prices.

To reduce our exposure to short-term fluctuations in the price of oil, NGLs, and natural gas, we sometimes enter into derivative contracts. These derivative contracts apply to only a portion of our production and provide only partial price protection against declines in oil, NGLs, and natural gas prices. These derivative contracts may expose us to risk of financial loss and limit the benefit to us of increases in prices.

Estimates of our reserves are uncertain and may prove inaccurate.

Numerous uncertainties are inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs, and natural gas reserves depend on several variable factors, including historical production from the area compared with production from other producing areas, and assumptions about:

the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
future operating costs;
severance and excise taxes;
development costs; and
workover and remedial costs.

Some or all of these assumptions may vary considerably from actual results. Estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows from reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenues and expenditures regarding our reserves will likely vary from estimates, and those variances may be material.


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The information regarding discounted future net cash flows should not be considered as the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on prices on the first day of the month for each month within the 12-month period before the end of the reporting period and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by these factors:

the amount and timing of actual production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.

In addition, the 10% per year discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the oil and natural gas industry.

If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may have to take write-downs of our oil and natural gas properties, the carrying value of our drilling rigs or our natural gas gathering and processing systems.

We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10% per year. Application of the ceiling test generally requires pricing future revenue at the unweighted arithmetic average of the price on the first day of month for each month within the 12-month period before the end of the reporting period, unless prices were defined by contractual arrangements, and requires a write-down for accounting purposes if the ceiling is exceeded. We may be required to write-down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would cause a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible later. Because our ceiling tests use a rolling 12-month look back average price it is possible that a write down during a reporting period will not remove the need for us to take additional write downs in one or more succeeding periods. This would be the case when months with higher commodity prices roll off the 12-month period and are replaced with more recent months having lower commodity prices.

Our drilling equipment, transportation equipment, gas gathering and processing systems, and other property and equipment are carried at cost. We are required to periodically test to see if these values, including associated goodwill and other intangible assets, have been impaired whenever events or changes in circumstances suggest the carrying amount may not be recoverable. If any of these assets are determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property, equipment, and related intangible assets. Once these values have been reduced, they are not reversible.

Our operations present inherent risks of loss that, if not insured or indemnified against, could hurt our results of operations.

Our contract drilling operations are subject to many hazards inherent in the drilling industry, including blowouts, cratering, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment, and damage or loss from inclement weather. Our exploration and production and mid-stream operations are subject to these and similar risks. These events could cause personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage, and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our drilling customers by contract for some of these risks. If we cannot transfer these risks to drilling customers by contract or indemnification agreements (or to the extent we assume obligations of indemnity or assume liability for certain risks under our drilling contracts), we seek protection from some of these risks through insurance. However, some risks are not covered by insurance and we cannot assure you that the insurance we have or the indemnification agreements we have will adequately protect us against liability from the consequences of the hazards described above. An event not fully insured or indemnified against, or the failure of a customer to meet its indemnification obligations, could cause substantial losses. In addition, we cannot assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.


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We do not operate many of the wells in which we own an interest. Our operating risks for those wells and our ability to influence the operations for those wells are less subject to our control. Operators of those wells may act in ways not in our best interests.

Governmental and environmental regulations could hurt our business.

Our business is subject to federal, state, and local laws and regulations on taxation, the exploration for and development, production, and marketing of oil and natural gas, and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties, and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning our oil and natural gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the number of wells drilled or the allowable production from successful wells, which could limit our revenues.

We are (or could become) subject to complex environmental laws and regulations adopted by the jurisdictions where we own or operate. We could incur liability to governments or third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could discharge these materials into the environment in many ways including:

from a well or drilling equipment at a drill site;
from gathering systems, pipelines, transportation facilities, and storage tanks;
damage to oil and natural gas wells resulting from accidents during normal operations;
sabotage; and
blowouts, cratering, and explosions.

Because the requirements imposed by laws and regulations frequently change, we cannot assure you that future laws and regulations, including changes to existing laws and regulations, will not hurt our business. The Congress and White House administration may impose or change laws and regulations that will hurt our business. Stricter standards, greater regulation, and more extensive permit requirements, could increase our future risks and costs related to environmental matters. In addition, because we acquire interests in properties operated in the past by others, we may be liable for environmental damage caused by the former operators, which liability could be material.

Any future implementation of price controls on oil, NGLs, and natural gas would affect our operations.

Certain groups have asserted efforts to have the United States Congress impose price controls on either oil, natural gas, or both. There is no way at this time to know what result these efforts will have nor, if implemented, their effect on our operations. However, it is possible that these efforts, if successful, would limit the amount we might get for our future oil, NGLs, and natural gas production. Any future limits on the price of oil, NGLs, and natural gas could also cause hurting the demand for our drilling services.

Provisions of Delaware law and our by-laws and charter could discourage change in control transactions and prevent shareholders from receiving a premium on their investment.

Our by-laws and charter provide for a classified board of directors with staggered terms and authorizes the board of directors to set the terms of preferred stock. In addition, our charter and Delaware law contain provisions that impose restrictions on business combinations with interested parties. Because of our by-laws, charter, and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. These provisions may make it more difficult for our shareholders to benefit from transactions opposed by an incumbent board of directors.


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New technologies may cause our exploration and drilling methods to become obsolete, resulting in an adverse effect on our production.

Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may allow them to implement new technologies before we can. We cannot be certain that we can implement technologies timely or at a cost acceptable to us. One or more technologies that we use or that we may implement may become obsolete or may not work as we expected and we may be hurt.

We may be affected by climate change and market or regulatory responses to climate change.

Climate change, including the impact of potential global warming regulations, could have a material adverse effect on our results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse gasses, including diesel exhaust, could significantly increase our operating costs. Restrictions on emissions could also affect our customers that (a) use commodities we carry to produce energy, (b) use significant energy in producing or delivering the commodities we carry, or (c) manufacture or produce goods that consume significant energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases, government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or emissions reductions could materially affect the markets for the commodities associated with our business, which could have a material adverse effect on our results of operations, financial condition, and liquidity. Government incentives encouraging the use of alternative sources of energy could also affect certain of our customers and the markets for certain of the commodities associated with our business in an unpredictable manner that could alter our business activities. Finally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change. These factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the business activity we conduct and have a material adverse effect on our results of operations, financial condition, and liquidity.

The results of our operations depend on our ability to transport oil, NGLs, and gas production to key markets.

The marketability of our oil, NGLs, and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems, refineries, and other transportation sources. The unavailability of or lack of capacity on these systems and facilities could cause the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil, NGLs, and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, and general economic conditions could hurt our ability to produce, gather and, transport oil, NGLs, and natural gas.

Losing one or several of our larger customers could have a material adverse effect on our financial condition and results of operations.

During 2017, sales to Sunoco Logistics accounted for 10% of our oil and natural gas revenues. QEP Resources, Inc. was our largest drilling customer accounting for approximately 26% of our total contract drilling revenues. And for our mid-stream segment, ONEOK, Inc. accounted for approximately 36% of our revenues. No other third party customer accounted for 10% or more of any of our individual segment revenues. Any of our customers may choose not to use our services and losing several our larger customers could have a material adverse effect on our financial condition and results of operations if we could not find replacements.

Shortage of completion equipment and services could delay or otherwise hurt our oil and natural gas segment's operations.

As there is an increase in horizontal drilling activity in certain areas, shortages could cause the availability of third party equipment and services required for completing wells drilled by our oil and natural gas segment. We could experience delays in completing some of our wells. Although we can try to reduce the delays associated with these services, we anticipate these services will be in high demand for the immediate future and could delay, restrict, or curtail part of our exploration and development operations, which could in turn harm our results.

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Our mid-stream segment depends on certain natural gas producers and pipeline operators for a significant portion of its supply of natural gas and NGLs. Losing any of these producers could cause a decline in our volumes and revenues.

We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. While some of these producers are subject to long-term contracts, we may not negotiate extensions or replacements of these contracts on favorable terms, if at all. Losing all or even a portion of the natural gas volumes supplied by these producers, because of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we acquired comparable volumes from other sources.

The counterparties to our commodity derivative contracts may not perform their obligations to us, which could materially affect our cash flows and results of operations.

To reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into commodity derivative contracts for a significant portion of our forecasted oil, NGLs, and natural gas production. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities, and to the ability of counterparties under our commodity derivative contracts to satisfy their obligations to us. If one or more of our counterparties is unable or unwilling to pay us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.

Reliance on management.

We depend greatly on the efforts of our executive officers and other key employees to manage our operations. The loss or unavailability of any of our executive officers or other key employees could have a material adverse effect on our business.

We are subject to various claims and litigation that could ultimately be resolved against us requiring material future cash payments and/or future material charges against our operating income and materially impairing our financial position.

The nature of our business makes us highly susceptible to claims and litigation. We are subject to various existing legal claims and lawsuits, which could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. Any claims or litigation, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.

Derivative regulations in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was passed by Congress and signed into law. The Act contains significant derivative regulations, requiring that certain transactions be cleared on exchanges and a requirement to post cash collateral (commonly called margin) for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes several defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. 

We use crude oil and natural gas derivative instruments regarding a portion of our expected production to reduce commodity price uncertainty and enhance the predictability of cash flows relating the marketing our crude oil and natural gas. As commodity prices increase, our derivative liability positions increase; however, none of our current derivative contracts require posting margin or similar cash collateral when there are changes in the underlying commodity prices referred to in these contracts.

Depending on the rules and definitions adopted by the CFTC, we could have to post collateral with our dealer counterparties for our commodities derivative transactions. Such a requirement could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral would cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes, or would require us to increase our level of debt. In addition, a requirement for our counterparties to post collateral would likely cause additional costs being passed on to us, thereby decreasing the effectiveness of our derivative contracts and our profitability.


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Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause increased costs and additional operating restrictions or delays.

Hydraulic-fracturing is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense subsurface rock formations. Our oil and natural gas segment routinely apply hydraulic-fracturing techniques to many of our oil and natural gas properties, including our unconventional resource plays in the Granite Wash of Texas and Oklahoma, the Marmaton and Hoxbar of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. Hydraulic-fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and published permitting guidance addressing the performance of such activities using diesel. The EPA is also seeking to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the bureau of Land Management has imposed requirements for hydraulic fracturing activities of federal lands. In addition, Congress has occasionally considered legislation to provide for federal regulation of hydraulic-fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.

Certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure of fracking fluids, waste disposal, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. Besides state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling and/or hydraulic fracturing. If state, local, or municipal legal restrictions are adopted in areas where we are conducting, or plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant, experience delays or curtailment pursuing exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating a review of hydraulic-fracturing practices, and a committee of the United States House of Representatives investigated hydraulic-fracturing practices. Furthermore, several federal agencies are analyzing, or have been requested to review, many environmental issues associated with hydraulic fracturing. The EPA is evaluating the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods.

And certain members of the Congress have called on the U.S. Government Accountability Office to investigate how hydraulic fracturing might hurt water resources, the U.S. Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, and uncertainties associated with those estimates. These ongoing or proposed studies, depending on their course and results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory processes.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or implementing regulations regarding hydraulic fracturing could cause a decrease in completing of new oil and gas wells, increased compliance costs and time, which could hurt our financial position, results of operations, and cash flows.

Our ability to produce crude oil, natural gas, and associated liquids economically and in commercial quantities could be impaired if we cannot acquire adequate supplies of water for our drilling operations and/or completions or cannot dispose of or recycle the water we use at a reasonable cost and under applicable environmental rules.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect intended to provide coverage for losses solely related to

35


hydraulic fracturing operations; however, our general liability and excess liability insurance policies might cover third-party claims related to hydraulic fracturing operations and associated legal expenses depending on the specific nature of the claims, the timing of the claims, and the specific terms of such policies.

Uncertainty regarding increased seismic activity in Oklahoma and Kansas.

We conduct oil and natural gas exploration, development and drilling activities in Oklahoma, Kansas, and elsewhere. In recent years, Oklahoma and Kansas has experienced a significant increase in earthquakes and other seismic activity. Some parties believe there is a correlation between certain oil and gas activities and the increased occurrence of earthquakes. The extent of this correlation is the subject of studies by both state and federal agencies the results of which remain uncertain. We cannot state at this time what if any impact this seismic activity may have on us or our industry.

The hydraulic fracturing process on which we depend to produce commercial quantities of crude oil, natural gas, and associated NGLs from many reservoirs requires the use and disposal of significant quantities of water.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our oil and natural gas segment operations, could adversely affect our operations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development or production of oil and natural gas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and, use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

We may decide not to drill some prospects we have identified, and locations we drill may not yield oil, NGLs, and natural gas in commercially viable quantities.

Our oil and natural gas segment's prospective drilling locations are in various stages of evaluation, ranging from a prospect ready to drill to a prospect that will require additional geological and engineering analysis. Based on many factors, including future oil, NGLs, natural gas prices, the generation of additional seismic or geological information, and other factors, we may decide not to drill one or more of these prospects. As a result, we may not increase or maintain our reserves or production, which in turn could have an adverse effect on our business, financial position, and results of operations. In addition, the SEC's reserve reporting rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of booking. At December 31, 2017, we had 99 proved undeveloped drilling locations. If we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may have to reclassify such reserves as unproved reserves. The reclassification of those reserves could also have a negative effect on the borrowing base under our credit facility.

The cost of drilling, completing, and operating a well is often uncertain, and cost factors can hurt the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, NGLs, and natural gas to be commercially viable after drilling, operating, and other costs.

The borrowing base under our credit agreement is determined semi-annually at the discretion of the lenders and is based in a large part on the prices for oil, NGLs, and natural gas.

Significant declines in oil, NGLs, and natural gas prices may cause a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and therefore the borrowings permitted to be outstanding under our credit agreement. If outstanding borrowings are over the borrowing base, we must (a) repay the amount in excess of the borrowing base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments under our credit agreement.

Potential listing of species as “endangered” under the federal Endangered Species Act could cause increased costs and new operating restrictions or delays on our operations and that of our customers, which could hurt our operations and financial results.

The federal Endangered Species Act, referred to as the “ESA,” and analogous state laws regulate a variety of activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the

36


ESA or their habitats. The designation of previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future undertake operations. The U.S. Fish and Wildlife Service and the National Marine Fisheries in 2016 issued final revised definitions relating to impacts on critical habitats for potentially endangered species allowing exclusion of certain areas so long as they will not result in the extinction of the species. In 2017, the Western Governor’s Association issued a Policy Resolution calling on Congress to amend and reauthorize the ESA based upon seven broad goals to make the act more workable and understandable. In December 2017, the Interior Department announced that it is working on possible changes to the ESA with the U.S. Fish and Wildlife Service to revise the regulations for listing endangered and threatened species and for designation of critical habitat. The presence of protected species in areas where we provide contract drilling or mid-stream services or conduct exploration and production operations could impair our ability to timely complete or carry out those services and, consequently, adversely affect our results of operations and financial position.

Constructing our new proprietary BOSS drilling rigs is subject to risks, including delays and cost overruns, and may not meet our expectations.

We have designed and built several new proprietary 1,500 horsepower AC electric drilling rigs, which we call BOSS drilling rigs. This new design should position us to better meet the demands of our customers. Constructing any future new BOSS drilling rigs is subject to the risks of delays or cost overruns inherent in any large construction project because of numerous possible factors, including:

shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
unanticipated increases in the cost of equipment, labor and raw materials used in construction of our drilling rigs, particularly steel;
weather interferences;
difficulties in obtaining necessary permits or in meeting permit conditions;
unforeseen design and engineering problems;
failure or delay in obtaining acceptance of the drilling rig from our customer;
failure or delay of third party equipment vendors or service providers; and
lack of demand from the downturn in the oil and gas industry.

On our new BOSS drilling rigs, there can be no assurance we will:

obtain additional new-build contract opportunities; or
improve our financial condition, results of operations or prospects because of the new drilling rigs.

While we hold certain patents regarding our BOSS drilling rig design, it is still possible that third parties may claim we infringe their intellectual property rights. We may receive notices from others claiming that our BOSS drilling rig design infringes on their intellectual property rights. In that event we may resolve these claims by signing royalty and licensing agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to decline. Besides money damages, in some jurisdictions plaintiffs can seek injunctive relief that may limit or prevent marketing and use of our drilling rigs that have infringing technologies.

Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks or cyber-attacks may significantly affect the energy industry, and economic conditions, including our operations and our customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. A

37


cyber incident could result in information theft, data corruption, operational disruption and/or financial loss. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

The oil and natural gas industry has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of natural gas reserves, and perform other activities related to our businesses. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

Deliberate attacks on our assets, or security breaches in our systems or infrastructure, the systems or infrastructure of third-parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability, including the following:

a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber-attack on our facilities may result in equipment damage or failure;
a cyber-attack on mid-stream or downstream pipelines could prevent our product from being delivered, resulting in a loss of revenues;
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.

Implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. We are not aware that any such breaches have occurred.

We are the subject of putative class action lawsuits that may result in substantial expenditures and divert management's attention.

We are the subject of putative class action lawsuits in Oklahoma with respect to the alleged failure to pay interest with on untimely royalty payments and with respect to the alleged underpayment of royalties. These lawsuits seek various remedies, including damages, injunctive relief, and attorney’s fees. For additional information on these lawsuits, see Item 3 Legal Proceedings in this Annual Report on Form 10-K.

Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition.

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Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.

Item 1B. Unresolved Staff Comments

None.

Item 2.     Properties

The information called for by this item was consolidated with and disclosed in connection with Item 1 above.

Item 3.     Legal Proceedings
Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.
Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson, and Charlotte Abernathy are the Plaintiffs and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs sought to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. On May 11, 2012 the court of civil appeals reversed the trial court’s order certifying the class. The Plaintiffs petitioned the Supreme Court for certiorari and on October 8, 2012, the Plaintiff’s petition was denied. On January 22, 2013, the Plaintiffs filed a second request to certify a class of royalty owners slightly smaller than their first attempt. Since then, the Plaintiffs have further amended their proposed class to just include royalty owners entitled to royalties under certain leases in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, besides the defenses described above, we argued that the amended class definition is still deficient under the court of civil appeals opinion reversing the initial class certification. Closing arguments were held on December 2, 2014. There is no timetable for when the court will issue its ruling. The merits of Plaintiffs’ claims will remain stayed while class certification issues are pending.

Cockerell Oil Properties, Ltd., v. Unit Petroleum Company, No. 16-cv-135-JHP, United States District Court for the Eastern District of Oklahoma.

On March 11, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Cockerell Oil Properties, Ltd., v. Unit Petroleum Company in LeFlore County, Oklahoma. We removed the case to federal court in the Eastern District of Oklahoma. The plaintiff alleges that Unit Petroleum wrongfully failed to pay interest with respect to untimely royalty payments under Oklahoma’s Production Revenue Standards Act. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of royalty owners in our Oklahoma wells. We have asserted several defenses including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was timely made or has accrued interest under Oklahoma law. At this point, the court has not taken any action on the issue of class certification.

Chieftain Royalty Company v. Unit Petroleum Company, No. CJ-16-230, District Court of LeFlore County, Oklahoma.

On November 3, 2016, a putative class action lawsuit was filed against Unit Petroleum Company styled Chieftain Royalty Company v. Unit Petroleum Company in LeFlore County, Oklahoma. Plaintiff alleges that Unit Petroleum breached its duty to pay royalties on natural gas used for fuel off the lease premises. The lawsuit seeks actual and punitive damages, an accounting, injunctive relief, and attorney’s fees. Plaintiff is seeking relief on behalf of Oklahoma citizens who are or were royalty owners in our Oklahoma wells. We filed a motion to dismiss on the basis that the claims asserted by the Plaintiff and the putative class are barred because they have already been asserted by the putative class in the Panola lawsuit and are subject to its reversal of class certification. The court denied our motion to dismiss and we have asked the court to certify its order so that it can be immediately appealed. That issue is still pending before the court. If we do not ultimately prevail on our claim of issue preclusion, we have several other defenses, including that the case cannot be properly certified as a class action because of the wide variety of circumstances that determine whether a royalty payment was wrongfully withheld. At this point, the issue of class certification has not been set before the court.

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We continue to vigorously defend against each of the pending claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

Item 4.     Mine Safety Disclosures

Not applicable.

PART II

Item 5.     Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Our common stock trades on the New York Stock Exchange under the symbol “UNT.” This table identifies the high and low closing sales prices per share of our common stock for the periods indicated:
 
2017
 
2016
Quarter
High
 
Low
 
High
 
Low
First
$
30.25

 
$
20.73

 
$
12.51

 
$
4.41

Second
$
24.26

 
$
16.47

 
$
17.81

 
$
8.44

Third
$
21.55

 
$
15.42

 
$
18.82

 
$
11.29

Fourth
$
22.83

 
$
17.20

 
$
28.11

 
$
16.44


On February 13, 2018, the closing sale price of our common stock, as reported by the NYSE, was $20.16 per share. On that date, there were approximately 793 holders of record of our common stock.

We have declared no cash dividends on our common stock. Any future determination by our board of directors to pay dividends on our common stock will be made only after considering our financial condition, results of operations, capital requirements, and other relevant factors. Our bank credit agreement and the Notes prohibit the payment of cash dividends on our common stock under certain circumstances. For further information regarding our bank credit agreement and the Notes agreement’s impact on our ability to pay dividends see “Our Credit Agreement and Senior Subordinated Notes” under Item 7 of this report.


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Performance Graph. The following graph and related information shall not be deemed “soliciting material” or be deemed to be “filed” with the SEC, nor will this information be incorporated by reference into any future filing, except to the extent that we specifically incorporate it by reference into that filing.

Set forth below is a line graph comparing our cumulative total shareholder return on our common stock with the cumulative total return of the S&P 500 Stock Index, S&P 600 Oil and Gas Exploration & Production and our peer group which includes Helmerich & Payne, Inc., Patterson – UTI Energy Inc., and Pioneer Energy Services Corp. The graph below assumes an investment of $100 at the beginning of the period. The shareholder return set forth below is not necessarily indicative of future performance.

chart-43ab971e32e05267972.jpg


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Item 6.     Selected Financial Data

The following table shows selected consolidated financial data. The data should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a review of 2017, 2016, and 2015 activity.
 
As of and for the Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(In thousands except per share amounts)
 
Revenues
$
739,640

 
$
602,177

 
$
854,231

 
$
1,572,944

 
$
1,351,850

 
Net income (loss)
$
117,848

 
$
(135,624
)
(3) 
$
(1,037,361
)
(2) 
$
136,276

(1) 
$
184,746

 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
 
Basic
$
2.31

 
$
(2.71
)
 
$
(21.12
)
 
$
2.80

 
$
3.83

 
Diluted
$
2.28

 
$
(2.71
)
 
$
(21.12
)
 
$
2.78

 
$
3.80

 
Total assets
$
2,581,452

 
$
2,479,303

(3) 
$
2,799,842

(2) 
$
4,463,473

(1) 
$
4,010,546

 
Long-term debt (4)
$
820,276

 
$
800,917

 
$
918,995

 
$
801,908

 
$