10-K 1 unt-20161231x10k.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, 2016
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
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
Rights to Purchase Series A Participating
Cumulative Preferred Stock
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 [ ]    No [x]
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    [ ]
 
Accelerated filer    [x]
 
Non-accelerated filer    [ ]
 
Smaller reporting company    [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ]    No [x]
As of June 30, 2016, 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, 2016) held by non-affiliates was approximately $495,132,341. 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 10, 2017
Common Stock, $0.20 par value per share
51,650,140 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 3, 2017. 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 121



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 terms of 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 which are 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 sum of the 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 that can be 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 – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 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 that are 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 (in regards to reserves) – If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually 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 in order 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, 2016

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 made available in print, free of charge, 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 regarding our company 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 free of charge on our website or in print to any shareholder who requests them. We may from time to time 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, in addition to 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 of these companies may conduct operations through subsidiaries of their own.

The following table provides certain information about us as of February 10, 2017:
Oil and Natural Gas
 
Completed gross wells in which we own an interest
6,542

Contract Drilling
 
Number of drilling rigs available for use
94

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
25


1


2016 SEGMENT OPERATIONS HIGHLIGHTS

Oil and Natural Gas
Sold non-core assets with proceeds of $67.2 million.
Resumed drilling activities in the fourth quarter with a first drilling rig being placed into service in October in the Southern Oklahoma Hoxbar Oil Trend (SOHOT) play and a second drilling rig was placed into service in December in the Granite Wash play.

Contract Drilling
Utilization cycle turned around:
Started year with 26 drilling rigs operating
Bottomed mid-year at 13 rigs operating
Exited year with 21 rigs operating, with momentum of additional rigs returning to work in early 2017
Placed one new BOSS drilling rig into service during the year.
Sold one older SCR drilling rig.
Achieved the best safety performance record in history of company, beating last year’s previous best.

Mid-Stream
Gas gathered volumes increased 18% over 2015.
Connected four new well pads with a total of 18 new wells to our Pittsburgh Mills gathering system in 2016, increasing our total gathered volume to approximately 150 MMcf per day.
Began operations of the new fee-based Snow Shoe gathering system located in Centre County Pennsylvania in the first quarter of 2016.
Upgraded our Segno gathering system to increase gathering and dehydration capacity to 120 MMcf per day as total throughput volume increased to approximately 90 MMcf per day.
Completed construction of a pipeline connection that allows us to receive an additional 10 MMcf per day of fee-based volume from a producer at our Cashion facility.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 15 of our Notes to Consolidated Financial Statements in Item 8 of this report for information with respect to each of our segment’s revenues, profits or losses, and total assets.


2


OIL AND NATURAL GAS

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

When we are the operator of a property, we generally 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 develop a system in the area.

The following table presents certain information regarding our oil and natural gas operations as of December 31, 2016:
Our Divisions/Area
Number
of
Gross
Wells
 
Number
of Net
Wells
 
Number
of Gross
Wells in
Process
 
Number
of Net
Wells in
Process
 
2016 Average
Net Daily Production
 
 
 
 
Natural
Gas
(Mcf)
 
Oil
(Bbls)
 
NGLs (Bbls)
West division
1,248

 
440.83

 

 

 
56,422

 
2,261

 
5,154

East division
201

 
106.93

 

 

 
8,076

 
21

 
1

Central division
5,096

 
1,868.74

 
4

 
2.76

 
87,782

 
5,843

 
8,544

Total
6,545

 
2,416.50

 
4

 
2.76

 
152,280

 
8,125

 
13,699


As of December 31, 2016, we did not have any 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, and Hardin Counties, Texas, we completed four operated horizontal wells (average working interest 99.4%) in 2016. All four wells were completed as gas/condensate producers. Annual production from our Wilcox play averaged 94.1 MMcfe per day (12% oil, 31% NGLs, 57% natural gas) which is an increase of approximately 22% compared to 2015. We averaged approximately 0.2 Unit drilling rigs operating during 2016 and we currently plan to use approximately 0.8 Unit drilling rigs operating during 2017. We anticipate completing approximately four vertical wells and three horizontal wells during 2017. In addition, we plan to complete approximately 12 behind pipe gas and liquids zones.

Central division. In our Southern Oklahoma Hoxbar Oil Trend (SOHOT) play, located in western Oklahoma primarily in Grady County, we completed three horizontal oil wells (average working interest 80.2%) in the Marchand zone of the Hoxbar interval. Annual production from western Oklahoma averaged 65.1 MMcfe per day (27% oil, 22% NGLs, 51% natural gas) which is a decrease of approximately 15% compared to 2015. During 2016, we averaged approximately 0.3 Unit drilling rigs operating and we currently plan to use approximately 0.75 Unit drilling rigs operating during 2017. We anticipate completing approximately seven horizontal Marchand wells in our SOHOT play during 2017.

In our Texas Panhandle Granite Wash play, we completed one extended lateral horizontal gas/condensate well (working interest 99.4%) in our Buffalo Wallow field. Annual production from the Texas Panhandle averaged 93.7 MMcfe per day (11% oil, 37% NGLs, 52% natural gas) which is a decrease of approximately 23% compared to 2015. During 2016, we averaged approximately 0.1 Unit drilling rigs operating and we currently plan to use approximately one Unit drilling rig operating during 2017. We anticipate completing approximately seven extended lateral Granite Wash horizontal wells in our Buffalo Wallow field during 2017.

In our Mississippian play in south central Kansas, we completed one horizontal oil well (working interest 100%). Annual production from Kansas averaged 6.2 MMcfe per day (62% oil, 9% NGLs, 29% natural gas) which is a decrease of approximately 45% compared to 2015. We anticipate completing approximately two horizontal wells in our Kansas Mississippian play during 2017.

3


East division. Over the last several years, activity in our East division has been limited due to low gas prices since this area does not generally have oil or NGLs associated with the gas. We did not drill any wells in this division during 2016.

Dispositions. We had non-core asset sales with proceeds, net of related expenses, of $33.1 million, $1.9 million, and $67.2 million in 2014, 2015, and 2016, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.

During the year (as well as certain 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 $73.7 million in 2014, $114.4 million in 2015, and $7.6 million in 2016 of costs being added to the total of our capitalized costs being amortized. We incurred a $76.7 million pre-tax ($47.7 million net of tax) non-cash ceiling test write-down of our oil and natural gas properties in 2014 due to the inclusion of the impaired value of those unproved properties and a reduction of the 12-month average commodity prices during the year. In 2015, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion net of tax) primarily due to the reduction of the 12-month average commodity prices during the year. 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) due to the reduction of the 12-month average commodity prices during the first three quarters of the year. We did not have a ceiling test write-down for the fourth quarter of 2016.





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,
 
2016
 
2015
 
2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled:
 
 
 
 
 
 
 
 
 
 
 
Development:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 
2

 
0.66

 
4

 
0.37

East division

 

 

 

 

 

Central division
9

 
3.57

 
21

 
8.12

 
115

 
74.07

Total oil
9

 
3.57

 
23

 
8.78

 
119

 
74.44

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
4

 
3.98

 
15

 
13.50

 
7

 
6.09

East division

 

 

 

 

 

Central division
7

 
1.12

 
18

 
11.50

 
49

 
31.91

Total natural gas
11

 
5.10

 
33

 
25.00

 
56

 
38.00

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 
1

 
1.00

 
1

 
0.80

East division

 

 

 

 

 

Central division

 

 
1

 
0.21

 
3

 
1.03

Total dry

 

 
2

 
1.21

 
4

 
1.83

Total development
20

 
8.67

 
58

 
34.99

 
179

 
114.27

Exploratory:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
1

 
1.00

 

 

 

 

East division

 

 

 

 

 

Central division

 

 

 

 
1

 
0.93

Total oil
1

 
1.00

 

 

 
1

 
0.93

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 

 

 
5

 
4.80

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total natural gas

 

 

 

 
5

 
4.80

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 

 

 
1

 
1.00

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total dry

 

 

 

 
1

 
1.00

Total exploratory
1

 
1.00

 

 

 
7

 
6.73

Total wells drilled
21

 
9.67

 
58

 
34.99

 
186

 
121.00






5


 
Year Ended December 31,
 
2016 (1)
 
2015
 
2014 (1)
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells producing or capable of producing:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
648

 
136.59

 
692

 
149.34

 
713

 
164.25

East division
18

 
0.72

 
28

 
1.79

 
42

 
1.91

Central division
908

 
497.25

 
907

 
498.75

 
997

 
497.10

Total oil
1,574

 
634.56

 
1,627

 
649.88

 
1,752

 
663.26

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
582

 
296.71

 
659

 
325.57

 
703

 
326.64

East division
181

 
105.85

 
1,358

 
466.22

 
1,401

 
466.79

Central division
4,181

 
1,367.87

 
4,217

 
1,376.94

 
4,265

 
1,390.05

Total natural gas
4,944

 
1,770.43

 
6,234

 
2,168.73

 
6,369

 
2,183.48

Total
6,518

 
2,404.99

 
7,861

 
2,818.61

 
8,121

 
2,846.74

_________________________ 
(1)
During 2016 and 2014, we had divestitures of 1,300 gross (407.70 net) wells and 1,716 gross (37.31 net) wells, respectively.

As of February 10, 2017, we were drilling or participating in four gross (3.08 net) wells started during 2017.

Cost incurred for development drilling includes $2.5 million, $58.6 million, and $199.7 million in 2016, 2015, and 2014, respectively, to develop previously booked proved undeveloped oil and natural gas reserves.

The following table summarizes our leasehold acreage at December 31, 2016: 
 
Year Ended December 31, 2016
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net (1)
 
Gross
 
Net
West division
258,341

 
81,769

 
100,847

 
69,368

 
359,188

 
151,137

East division
88,329

 
21,820

 
11,223

 
4,157

 
99,552

 
25,977

Central division
888,827

 
369,828

 
95,495

 
58,686

 
984,322

 
428,514

Total
1,235,497

 
473,417

 
207,565

 
132,211

 
1,443,062

 
605,628

_________________________ 
(1)
Approximately 82% (West – 79%; East – 95%; and Central – 84%) of the net undeveloped acres are covered by leases that will expire in the years 2017—2019 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,
 
2016
 
2015
 
2014
Average sales price per barrel of oil produced:
 
 
 
 
 
Price before derivatives
$
39.05

 
$
45.04

 
$
89.32

Effect of derivatives
1.45

 
5.75

 
0.11

Price including derivatives
$
40.50

 
$
50.79

 
$
89.43

Average sales price per barrel of NGLs produced:
 
 
 
 
 
Price before derivatives
$
11.26

 
$
10.12

 
$
30.95

Effect of derivatives

 

 

Price including derivatives
$
11.26

 
$
10.12

 
$
30.95

Average sales price per Mcf of natural gas produced:
 
 
 
 
 
Price before derivatives
$
1.98

 
$
2.25

 
$
4.03

Effect of derivatives
0.09

 
0.38

 
(0.11
)
Price including derivatives
$
2.07

 
$
2.63

 
$
3.92






































7


 
Year Ended December 31,
 
2016
 
2015
 
2014
Oil production (MBbls):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
589

 
422

 
377

All other west division fields
238

 
258

 
256

Total west division
827

 
680

 
633

East division
8

 
11

 
8

Central division:
 
 
 
 
 
Mendota field
248

 
343

 
407

All other central division fields
1,891

 
2,749

 
2,796

Total central division
2,139

 
3,092

 
3,203

Total oil production
2,974

 
3,783

 
3,844

NGLs production (MBbls):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
1,671

 
1,275

 
989

All other west division fields
216

 
266

 
235

Total west division
1,887

 
1,541

 
1,224

East division

 
6

 
6

Central division:
 
 
 
 
 
Mendota field
858

 
1,127

 
1,117

All other central division fields
2,269

 
2,600

 
2,281

Total central division
3,127

 
3,727

 
3,398

Total NGLs production
5,014

 
5,274

 
4,628

Natural gas production (MMcf):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
18,145

 
14,538

 
12,396

All other west division fields
2,506

 
3,259

 
3,552

Total west division
20,651

 
17,797

 
15,948

East division
2,956

 
6,846

 
7,719

Central division:
 
 
 
 
 
Mendota field
5,780

 
7,922

 
7,555

All other central division fields
26,348

 
32,981

 
27,632

Total central division
32,128

 
40,903

 
35,187

Total natural gas production
55,735

 
65,546

 
58,854

Total production (MBoe):
 
 
 
 
 
West division:
 
 
 
 
 
Jazz Wilcox field
5,284

 
4,120

 
3,431

All other west division fields
872

 
1,067

 
1,084

Total west division
6,156

 
5,187

 
4,515

East division
500

 
1,158

 
1,301

Central division:
 
 
 
 
 
Mendota field
2,069

 
2,790

 
2,783

All other central division fields
8,552

 
10,847

 
9,682

Total central division
10,621

 
13,637

 
12,465

Total production
17,277

 
19,982

 
18,281

Average production cost per equivalent Bbl (1)
$
5.62

 
$
7.06

 
$
7.70

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

8


Our Jazz Wilcox field in South Texas, which includes our Gilly, Segno, and Wildwood prospects and several smaller prospects, contained 26%, 24%, and 17% of our total proved reserves in 2016, 2015, and 2014, respectively, expressed on an oil equivalent barrels basis. Our Mendota field, located in the Granite Wash play in the Texas Panhandle, include 13%, 14%, and 17%, respectively of our total proved reserves in 2016, 2015, and 2014, respectively, expressed on an oil equivalent barrels basis. There are no other fields besides these 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, 2016
 
Oil
(MBbls)
 
NGLs (MBbls)
 
Natural
Gas
(MMcf)
 
Total
Proved
Reserves
(MBoe)
Proved developed:
 
 
 
 
 
 
 
West division
3,303

 
9,474

 
100,674

 
29,556

East division

 

 
38,227

 
6,371

Central division
9,421

 
19,028

 
208,220

 
63,152

Total proved developed
12,724

 
28,502

 
347,121

 
99,079

Proved undeveloped:
 
 
 
 
 
 
 
West division
399

 
1,365

 
16,273

 
4,476

East division

 

 
2,343

 
391

Central division
2,573

 
4,615

 
39,842

 
13,828

Total proved undeveloped
2,972

 
5,980

 
58,458

 
18,695

Total proved
15,696

 
34,482

 
405,579

 
117,774


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 connection with 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, 2016 and comprised 82% of the total proved developed future net income discounted at 10% and 83% 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 are responsible for reviewing 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 as well as the respective operational divisions for additional scrutiny. Major reserve changes on existing wells are reviewed on a regular basis 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 also 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 a number of 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).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Paradiso fulfills. As part of his 2016 continuing education hours, Mr. Paradiso attended 6 hours of formalized training during the 2016 RSC Reserves Conference relating to the definitions and disclosure guidelines contained 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 32 hours of formalized in-house training during 2016 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 more than 37 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 a number of 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 and has been a member of SPE since 1991.

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 thereafter 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 fluid contacts, if any, 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 on the basis of available geosciences and engineering data.

In the absence of 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 in 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 determined as 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 that are 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 that are 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, 2016, we had 40 gross proved undeveloped wells all of which we plan to develop within five years of initial disclosure at a net estimated cost of approximately $123.8 million. The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves for the years 2017—2021, as disclosed in our December 31, 2016 oil and natural gas reserve report, are shown below:
Year
 
Number of Gross Wells Planned
 
Estimated Development Cost
(In millions)
2017
 
13

 
$
41.3

2018
 
23

 
80.2

2019
 
4

 
2.3

2020
 

 

2021
 

 

 
 
40

 
$
123.8



11


Our proved undeveloped reserves reported at December 31, 2016 did not include reserves that 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 2016:
 
Oil
(MMBbls)
 
NGLs
(MMBbls)
 
Natural Gas (Bcf)
 
Total
(MMBoe)
Proved undeveloped reserves, January 1, 2016
2.0

 
6.5

 
68.5

 
19.9

Extensions and discoveries
1.5

 
2.3

 
19.2

 
7.0

Converted to developed
(0.1
)
 

 
(0.1
)
 
(0.1
)
Revisions of previous estimates
(0.4
)
 
(2.8
)
 
(28.4
)
 
(8.0
)
Sales of reserves

 

 
(0.7
)
 
(0.1
)
Proved undeveloped reserves, December 31, 2016
3.0

 
6.0

 
58.5

 
18.7


During 2016, we converted one proved undeveloped well locations into a proved developed well at a cost of approximately $2.5 million. The downward revision in the table above to our previous estimates were due to a number of factors including the removal of proved undeveloped reserves that are not part of our five-year development plan due to the decline in prices causing them to be uneconomic to drill and also due to a reduction in anticipated future capital expenditures.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2016, 2015, and 2014, 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 included in Item 8 of this report.

Contracts. Our oil production is sold at or near our wells under purchase contracts at prevailing prices in accordance with arrangements customary in the oil industry. Our natural gas production is sold to intrastate and interstate pipelines as well as 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 of them are market sensitive.

Customers. During 2016, sales to Sunoco Logistics and Valero Energy Corporation accounted for 24% and 11% of our oil and natural gas revenues, respectively. No other company accounted for more than 10% of our oil and natural gas revenues. During 2016, our mid-stream segment purchased $42.7 million of our natural gas and NGLs production and provided gathering and transportation services of $9.2 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 2015 and 2014, we eliminated intercompany revenues of $65.2 million and $89.6 million, respectively, attributable to the intercompany purchase of our production of natural gas and NGLs as well as 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 as well as other oil and natural gas companies. Our drilling operations are located 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


The following table identifies certain information concerning our contract drilling segment:
 
Year Ended December 31,
 
2016
 
2015
 
2014
Number of drilling rigs available for use at year end
94.0

 
94.0

 
89.0

Average number of drilling rigs owned during year
93.9

 
92.6

 
118.8

Average number of drilling rigs utilized
17.4

 
34.7

 
75.4

Utilization rate (1)
19
%
 
38
%
 
63
%
Average revenue per day (2)
$
19,154

 
$
20,950

 
$
17,318

Total footage drilled (feet in 1,000’s)
5,112

 
7,237

 
12,551

Number of wells drilled
358

 
516

 
894

_________________________
(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 number of 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, pumps to circulate the drilling fluid, blowout preventers, top drives, and drill pipe. As a result 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 the operation of 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 2016, 28 of our 94 drilling rigs were used in drilling services.

The following table shows certain information about our drilling rigs (including their distribution) as of February 10, 2017:
Divisions
Contracted
Rigs
 
Non-Contracted
Rigs
 
Total
Rigs
 
Average
Rated
Drilling
Depth
(ft)
Mid-Continent (1)
22

 
51

 
73

 
17,185

Rocky Mountain
6

 
15

 
21

 
19,929

Totals
28

 
66

 
94

 
17,798

_________________________
(1)
In 2016, our Panhandle and Gulf Coast divisions were consolidated into the Mid-Continent division.

The cyclical nature of the contract drilling business is reflected in drilling rig utilization rates. Drilling rig utilization in 2014 saw an increase of 17 drilling rigs running, going from 65 drilling rigs at the start of the year to 82 drilling rigs in November. The last month of 2014 reflected the beginning of the downward market we have experienced the last two years. At the end of 2015, our active drilling rig count was 26. Then in 2016, utilization continued downward bottoming out in May at 13 operating drilling rigs and as commodity prices began improving during the remainder of the year, we exited 2016 with 21 active rigs.

Mid-Continent. 2016’s low level of utilization brought further consolidation of this segment's operating divisions. The Gulf Coast and Texas Panhandle divisions were rolled into the Mid-Continent division under a single management team. The Mid-Continent division manages operations from Oklahoma, Texas, Louisiana, and Kansas. The division operated an average of 11.7 drilling rigs during 2016. As of December 31, 2016, this division was operating 15 drilling rigs, 10 of which were working in Oklahoma and the Texas Panhandle and five 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 a number of conventional and unconventional oil and gas fields. This division operated an average of

13


5.7 drilling rigs during 2016. We had two drilling rigs operating in the Pinedale Anticline of western Wyoming, three drilling rigs operating in the Bakken Shale of North Dakota, and one drilling rig operating in the Niobrara play in eastern Colorado at the end of 2016.

At any given time the number of drilling rigs we can work depends on a number of conditions besides demand, including the availability of qualified labor and the availability of needed drilling supplies and equipment. The impact of these conditions tends to affect the demand for our drilling rigs. Our average utilization rate for 2016, 2015, and 2014 was 19%, 38%, and 63%, respectively.

The following table shows the average number of our drilling rigs working by quarter for the years indicated:
 
2016
 
2015
 
2014
First quarter
20.6

 
50.1

 
67.9

Second quarter
13.5

 
30.7

 
73.5

Third quarter
16.0

 
31.2

 
79.1

Fourth quarter
19.5

 
27.2

 
80.9


Drilling Rig Fleet. The following table summarizes the changes to our drilling rig fleet in 2016. A more complete discussion of changes over the last three years follows the table:
Drilling rigs available for use at December 31, 2015
94

Drilling rigs sold
(1
)
Drilling rigs constructed
1

Total drilling rigs available for use at December 31, 2016
94


Dispositions, Acquisitions, and Construction.  During the first quarter of 2014, we sold four idle 3,000 horsepower drilling rigs to an unaffiliated third party. The proceeds from that sale were used in our construction program for our new proprietary 1,500 horsepower, AC electric drilling rig, called the BOSS drilling rig.

During 2014, three BOSS drilling rigs were constructed and placed into service for third-party operators.

In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer marketable in the current environment and based on the estimated market value from third-party assessments, we recorded a write-down of approximately $74.3 million, pre-tax. During 2015, we recorded an additional write-down on the drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. We 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.

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 subject to negotiation 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 in addition to providing the drilling rig. We are paid on

14


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 the loss of the well. We did not have any footage or turnkey contracts in 2016, 2015, or 2014. Because market demand for our drilling rigs as well as 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.

Customers. During 2016, QEP Resources, Inc. and Whiting Petroleum Corporation were our largest drilling customers accounting for approximately 28% and 18%, respectively, of our total contract drilling revenues. Our work for these customers were under multiple contracts and our business was not substantially dependent on any of these individual contracts. Consequently, 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 2016, 2015, and 2014, our contract drilling segment drilled 10, 38, and 134 wells, respectively, for our oil and natural gas segment, or 3%, 7%, and 15%, 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 the acquisition of 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 the similar terms and rates as the contracts entered into with unrelated third parties. We did not eliminate any revenue or expenses in our contract drilling segment during 2016. By providing drilling services for the oil and natural gas segment, we eliminated revenue of $22.1 million and $89.5 million during 2015 and 2014, respectively, from our contract drilling segment and eliminated the associated operating expense of $18.3 million and $62.4 million during 2015 and 2014, respectively, yielding $3.8 million and $27.1 million during 2015 and 2014, respectively, as a reduction to the carrying value of our oil and natural gas properties.

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, 25 active gathering systems, and approximately 1,465 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

The following table presents certain information regarding our mid-stream segment for the years indicated:
 
Year Ended December 31,
 
2016
 
2015
 
2014
Gas gathered—Mcf/day
419,217

 
353,771

 
319,348

Gas processed—Mcf/day
155,461

 
182,684

 
161,282

NGLs sold—gallons/day
536,494

 
577,513

 
733,406


Dispositions and Acquisitions. This segment did not have any significant dispositions or acquisitions during 2014, 2015, or 2016.

In 2014, our mid-stream segment had a $7.1 million pre-tax write-down of three of its systems, Weatherford, Billy Rose, and Spring Creek and in 2015, incurred a $27.0 million pre-tax write-down of its systems, Bruceton Mills, Spring Creek, and Midwell due to anticipated future cash flow and future development around these systems not being sufficient to support their carrying value. The estimated future cash flows were less than the carrying value on these systems.

15


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 do have some short-term contracts as well. Our customer agreements include the following 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, 2016, 76% of our mid-stream segment’s total volumes and 71% 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, 2016, 24% of our mid-stream segment’s total volumes and 29% of operating margins (as defined below) were under commodity-cased 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 2016, ONEOK Partners, L.P., Koch Energy Services, LLC, Range Resources Corporation, and Tenaska Resources, LLC, accounted for approximately 30%, 11%, 10%, and 10%, respectively, of our mid-stream revenues. We believe that if we lost any of these identified customers, there are other customers available to purchase our gas and NGLs. During 2016, 2015, and 2014 this segment purchased $42.7 million, $57.6 million, and $80.9 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $9.2 million, $7.6 million, and $8.7 million, 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 as well as our ability to grow our operations. Oil, NGLs, and natural gas prices have been volatile and we expect them to continue to be so. For each of the periods indicated, the following 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 taking into account the effect of derivatives:
 
Oil Price per Bbl
 
NGLs Price per Bbl
 
Natural Gas Price per Mcf
Quarter
High
 
Low
 
High
 
Low
 
High
 
Low
2014
 
 
 
 
 
 
 
 
 
 
 
First
$
98.09

 
$
90.51

 
$
41.62

 
$
36.75

 
$
5.00

 
$
4.25

Second
$
102.62

 
$
98.76

 
$
35.45

 
$
25.70

 
$
4.38

 
$
4.15

Third
$
98.95

 
$
90.70

 
$
31.08

 
$
29.32

 
$
3.88

 
$
3.36

Fourth
$
82.30

 
$
54.22

 
$
29.02

 
$
19.49

 
$
3.96

 
$
3.31

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



16


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 a variety of 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.

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 impact our operations.

Our contract drilling operations are dependent 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 are dependent 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 are highly dependent 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 of these 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, at times, be extremely intense.


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Our mid-stream segment competes with purchasers and gatherers of all types and sizes, including those affiliated with various producers, other major pipeline companies, as well as 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. In addition, 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 also 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 the terms of our partnership agreements, the general partner has broad discretionary authority to manage the business and operations of the partnership, including the authority to make decisions regarding the partnership’s participation in a drilling location or a property acquisition, the partnership’s expenditure of funds, and the distribution of funds to partners. Because the business activities of the limited partners and the general partner are not the same, conflicts of interest will exist and it is not possible 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 and conditions 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.

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 10, 2017, we had approximately 746 employees in our contract drilling segment, 266 employees in our oil and natural gas segment, 125 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. The following discussion of certain laws and regulations affecting our operations should not be relied upon 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 by subsequent 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

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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 is required to divest to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the subsequent 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 have 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 the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis 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 upon the pipeline’s demonstration of lack of market control in the relevant service market.

As a result of these changes, independent sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counter parties. We believe these changes generally have improved the access to markets for natural gas while, at the same time, 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 subsequent regulations may have on production and marketing of natural gas from our properties.

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 in favor of deregulation and the promotion of competition in the natural gas industry. Thus, 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. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, 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 tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments could result in 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 applicable 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 are not able to predict with certainty what effect, if any, 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 the filing of reports concerning operations and impose other requirements

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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 the regulation of 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 are unable to 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 are required to 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 who are 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 as well as 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 current industry best practices for unconventional oil and gas extraction facilities.

The EPA and the U.S. Army Corp of Engineers in 2015 proposed a new expansive definition of the “waters of the United States,” which rules has been stayed by courts pending conformity with the definition the United States Supreme Court previously established and whether such changes can be appealed by a person or entity directly to a United States Court of Appeals. In addition, the Army Corps of Engineers 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 that 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, 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 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. 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.

Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” or GHGs, may be contributing to warming of the Earth’s atmosphere. As a result there have been a variety of regulatory developments, proposals or requirements, and legislative initiatives that have been introduced in the United States (as well as 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.

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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 occurring 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 with respect to 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 with respect to 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 result in additional costs to reduce emissions of GHGs associated with our operations and possibly could adversely affect demand for the crude oil we gather, transport, store or otherwise handle in connection with our services.

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 Marmaton of Oklahoma, the Wilcox of Texas, and the Mississippian of Kansas. A committee of the U.S. House of Representatives has been conducting an investigation of hydraulic fracturing practices. Legislation has previously been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. The U.S. House of Representatives has previously passed a bill that would block the Department of Interior from regulating hydraulic fracturing in states that already have their own regulations in place; however, it is uncertain that such an act will ever be enacted. In addition, certain states in which we operate, including Texas, Oklahoma, Kansas, Colorado, and Wyoming have adopted, and other states as well as 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 impact 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 as well as 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 extremely small earthquakes, but they are almost always too small to be detected. With respect to 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 serve to delay or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations or increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.


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Other; Compliance Costs. We cannot predict future legislation or regulations. It is possible that some future laws, regulations, and/or ordinances could result in increasing our compliance costs or additional operating restrictions as well as those of our customers. It is also possible that such future developments could curtail the demand for fossil fuels which could adversely affect the demand for our services, which in turn could adversely affect our future results of operations. Likewise we cannot predict with any certainty whether any changes to temperature, storm intensity or precipitation patterns as a result 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 connection with 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, as well as information relating to long-lived assets attributable to those operations were immaterial. We no longer have any interests there or any other international operations.


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 in the future, 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 that we file with the SEC in the future will automatically update and supersede information contained 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;

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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 as well as 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 be required to record in future periods.

These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, and expected future developments as well as other factors we believe are appropriate in the circumstances. Whether actual results and developments will conform to our expectations and predictions is subject to a number of 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;
general economic, market, or business conditions;
the availability of and nature of (or lack of) business opportunities that 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;
our ability to successfully implement our pending technology conversion process relating to our financial and operational information systems; and
other factors, most of which are beyond our control.

You should not place undue reliance on any of these forward-looking statements. Except as required by law, we disclaim any current 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 the occurrence of unanticipated events.

In order to help provide you with a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made by us, the following discussion outlines some (but not all) of the factors that could in the future 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 is substantially dependent on the levels of expenditures by the oil and gas industry. A substantial or an extended decline in oil and gas prices could result in 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 are generally dependent 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, as well as 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 that are owed to us. These effects could have a material adverse effect on our financial condition, results of operations and cash flows.

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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 result in a reduction in demand for oilfield services and could adversely affect our financial condition, results of operations and cash flows.

Oil, NGLs, and Natural Gas Prices. In addition to 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 have a direct impact on our revenues, profitability, and cash flow as well as our ability to meet our projected financial and operational goals. The prices for oil, NGLs, and natural gas are determined on a number of factors beyond our control, including:

the demand for and supply of oil, NGLs, and natural gas;
current weather conditions in the continental United States (which can greatly influence the demand and prices for natural gas at any given time);
the amount and timing of oil, liquid natural gas, and liquefied petroleum gas imports and exports;
the ability of current distribution systems in the United States to effectively meet the demand for oil, NGLs, and natural gas at any given time, 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;
the costs of exploring for producing and delivering oil and gas;
technological advances affecting energy consumption; and
weather conditions.

Oil prices are extremely sensitive to influences domestic and foreign based on political, social or economic underpinnings, any one 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, at times, has tended to increase the volatility associated with these prices resulting in large differences in prices even on a week-to-week and month-to-month basis. All of these factors, especially when coupled with the fact that much of our product prices are determined on a daily basis, can, and at times do, lead to wide fluctuations in the prices we receive.

Based on our 2016 production, a $0.10 per Mcf change in what we receive for our natural gas production, without the effect of derivatives, would result in a corresponding $442,000 per month ($5.3 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 $238,000 per month ($2.9 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 $398,000 per month ($4.8 million annualized) change in our pre-tax operating cash flow.

In order 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 in part, but not on all of our production which only provides price protection 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 2016, all of our NGLs volumes and about half of our oil and 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 61% and 65% of our 2016 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 contained in Item 7.


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Uncertainty of Oil, NGLs, and Natural Gas Reserves; Ceiling Test. There are many uncertainties 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 included 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 a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning:

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 particular 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 with respect to our oil, NGLs, and natural gas reserves will likely vary from estimates and those variances may be material.

The information regarding discounted future net cash flows included in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. The use of 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 the following 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 use 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 the risks associated with our operations or the oil and natural gas industry in general.

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 result in 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 currently 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 currently have, and will continue to

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have, a certain amount of indebtedness. At December 31, 2016, we had $160.8 million of outstanding long-term debt under our credit agreement and the amount of the Notes, net of unamortized discount and debt issuance costs, was $640.1 million.

Depending on the amount of our debt, the cash flow needed to satisfy that debt and the covenants contained 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 in the event of a downturn in our business; 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 would be entitled to accelerate the payment of the outstanding indebtedness. If that were to happen, we would not have sufficient funds available (and probably would not be able to obtain the financing required) to meet our obligations.

The amount of our existing debt, as well as our future debt, if any, is, largely, based on the costs associated with the projects we undertake at any given time 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 a degree of control regarding the timing or the need to incur them. But, in some cases, unforeseen circumstances may arise, such as in the case of an unanticipated opportunity to make a large acquisition or the need to replace a costly drilling rig component due to an unexpected loss, which could force us to incur additional debt above that which we had expected or forecasted. Likewise, if our cash flow should prove to be insufficient to cover our current cash requirements we would need to increase our debt either through bank borrowings or otherwise.

RISK FACTORS

Many other factors could adversely affect our business. The following discussion describes the material risks currently known to us. However, additional risks that we do not know about or that we currently view as immaterial may also impair our business or adversely affect 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 as well as produce our oil, NGLs, and natural gas may be negatively affected.

Historically, oil, NGLs, and natural gas prices have been extremely volatile, with significant increases and significant price drops being experienced from time to time. In the future, various factors beyond our control will have a significant effect on oil, NGLs, and natural gas prices. Such factors include, among other things, the domestic and foreign supply of oil, NGLs, and natural gas, the price of foreign 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 a number of 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 in the future 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 available markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. Oil, NGLs, and natural gas surpluses could result in 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 adversely affect us.


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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 result in 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. As a result of 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 future 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 in the future. Any decline in prices in the future would have a negative impact on our future financial results as well as 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 a variety of 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;
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.


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

The drilling industry in which we operate is generally very competitive. Most drilling contracts are awarded on the basis of competitive bids, which may result in 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 on the basis of 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 substantially greater resources than we do.

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

Growth through acquisitions is not assured.

In the past, we have experienced growth in each of our segments, in part, through mergers and acquisitions. The contract land drilling industry, the exploration and development industry, as well as 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 that we would have the financial ability to pursue the opportunity. Additionally, we are likely to continue to face intense competition from other companies for available acquisition opportunities.

There can be no assurance that 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
successfully improve our financial condition, results of operations, business or prospects in any material manner as a result 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 the issuance of 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 a number of 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.


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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 $640.1 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, have the right to borrow up to $475.0 million under our credit agreement. As of February 10, 2017, we had $163.0 million outstanding borrowings under our credit agreement. Our level of indebtedness, the cash flow needed 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 in the event of a downturn in our business; 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 result in 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. In particular, these agreements will 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;
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 fail to comply with 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 as well as any other indebtedness to which a cross-acceleration or cross-default provision applies. If that occurs, we may not be able to make all of 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.

In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that 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.

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Historically, we have succeeded in increasing reserves after taking production into account through exploration and development. We have conducted these activities on our existing oil and natural gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves from these activities at acceptable costs. Lower prices of oil, NGLs, and natural gas may further limit the kinds of 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 that would be significantly larger than those consummated to date by us. We cannot assure you that we will successfully consummate any acquisition, that we will be able to 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 will have to pay higher prices and accept greater ownership risks than we have in the past.

Our exploration and production and mid-stream operations involve a high degree of business and financial risk which could adversely affect us.

Exploration and development involve numerous risks that may result in 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 that 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.

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 as a result 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 the development of other producing properties within the gathering system’s area of operation; and
demand for natural gas and its constituents.


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Many of the wells from which we gather and process natural gas are operated by other parties. As a result, 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 that are not in our best interests.

Competition for experienced technical personnel may negatively impact 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 extremely 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.

In order 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 to be inaccurate.

There are numerous uncertainties 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 a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning:

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. For these reasons, estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any particular 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 with respect to our reserves will likely vary from estimates, and those variances may be material.

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 the following 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 in general.


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If oil, NGLs, and natural gas prices decrease or are unusually volatile, we may be required 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 prior to 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 result in 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 at a later date. 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 adversely affect 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. Any of these events could result in 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. To the extent that we are unable to 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 do have or the indemnification agreements we have entered into will adequately protect us against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a customer to meet its indemnification obligations, could result in 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.

In addition, we are not the operator of many of our wells. As a result, 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 that are not in our best interests.

Governmental and environmental regulations could adversely affect 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 total number of wells drilled or the allowable production from successful wells, which could limit our revenues.


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We are (or could become) subject to complex environmental laws and regulations adopted by the various 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 potentially discharge these materials into the environment in any number of ways including the following:

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; and
blowouts, cratering, and explosions.

Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. The current Congress and White House administration may impose or change laws and regulations that will adversely affect our business. With the trend toward stricter standards, greater regulation, and more extensive permit requirements, our risks related to environmental matters and our environmental expenditures could increase in the future. In addition, because we acquire interests in properties that have been 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 some form of 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 serve to limit the amount that we might be able to get for our future oil, NGLs, and natural gas production. Any future limits on the price of oil, NGLs, and natural gas could also result in adversely affecting 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 the provisions 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. As a result, these provisions may make it more difficult for our shareholders to benefit from transactions that are opposed by an incumbent board of directors.

New technologies may cause our current 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 in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete or may not work as we expected and we may be adversely affected.

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 that we carry to produce energy, (b) use significant amounts of energy in producing or delivering the commodities we carry, or (c) manufacture or produce goods that consume significant amounts of energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant

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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 in turn 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. Any of these factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the amount of 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 available capacity on these systems and facilities could result in 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 adversely affect our ability to produce, gather and, transport oil, NGLs, and natural gas.

The loss of one or a number of our larger customers could have a material adverse effect on our financial condition and results of operations.

During 2016, sales to Sunoco Logistics and Valero Energy Corporation accounted for 24% and 11% of our oil and natural gas revenues, respectively. QEP Resources, Inc. and Whiting Petroleum Corporation were our largest drilling customers accounting for approximately 28% and 18%, respectively, of our total contract drilling revenues. And for our mid-stream segment, ONEOK Partners, L.P., Koch Energy Services, LLC, Range Resources Corporation, and Tenaska Resources, LLC, accounted for approximately 30%, 11%, 10%, and 10%, respectively, of our revenues. No other third party customer accounted for 10% or more of our revenues. Any of our customers may choose not to use our services and the loss of a number of 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 adversely affect our oil and natural gas segment's operations.

As there is an increase in horizontal drilling activity in certain areas, shortages could result in the availability of third party equipment and services required for the completion of wells drilled by our oil and natural gas segment. We could experience delays in completing some of our wells. Although we can take steps to try to reduce the delays associated with these services, we anticipate that 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.

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. The loss of any of these producers could result in 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 be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these producers, as a result of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we were able to acquire comparable volumes from other sources.

The counterparties to our commodity derivative contracts may not be able to 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, as well as 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 make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.

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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 included 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, including a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral (commonly referred to as 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 a number of defined terms that will be 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 with respect to a portion of our expected production in order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas. As commodity prices increase, our derivative liability positions increase; however, none of our current derivative contracts require the posting of margin or similar cash collateral when there are changes in the underlying commodity prices that are referred to in these contracts.

Depending on the rules and definitions adopted by the CFTC, we could be required 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 result in additional costs being passed on to us, thereby decreasing the effectiveness of our derivative contracts and our profitability.

Proposed federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in 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 from time to time 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

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(RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of 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 has conducted an investigation of hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is currently evaluating the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods.

Additionally, certain members of the Congress have previously called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect 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, as well as 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 the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect 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 are unable to acquire adequate supplies of water for our drilling operations and/or completions or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with 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 that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, it is possible that 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, as well as 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 that there is a correlation between certain oil and gas activities and the increased occurrence of earthquakes. The extent of this correlation, if any, 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 in the future.

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 impact our operations. Moreover, 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

36


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 of the prospects we have identified, and locations that we do 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 that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of 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 be able to 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 include a general requirement 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 the date of booking. At December 31, 2016, we had 40 proved undeveloped drilling locations. To the extent that 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 be required 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 adversely affect 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 result in 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 in excess of the borrowing base, we must (a) repay the loan in excess of the borrowing base, (b) dedicate additional properties to the borrowing base, or (c) begin monthly principal payments in accordance with our credit agreement.

Potential listing of species as “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions or delays on our operations and that of our customers, which could adversely affect 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 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 ares so long as they will not result in the extinction of the species. 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.


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The construction of 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 refer to as BOSS drilling rigs. This new design is intended to position us to more effectively meet the demands of our customers. The construction of any future new BOSS drilling rigs is subject to the risks of delays or cost overruns inherent in any large construction project as a result of numerous possible factors, including the following:

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.

As to our new BOSS drilling rigs, there can be no assurance that we will:

obtain additional new-build contract opportunities; or
successfully improve our financial condition, results of operations or prospects as a result 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 choose to resolve these claims by entering into royalty and licensing agreements, redesigning the drilling rig, or paying damages. These outcomes may cause operating margins to decline. In addition to money damages, in some jurisdictions plaintiffs can seek injunctive relief that may limit or prevent marketing and utilizing our drilling rigs that have infringing technologies.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of natural gas, oil and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Although we utilize various procedures and controls to mitigate our exposure to such risk, cyber attacks are evolving and unpredictable. These attacks could include, but are not limited to, malicious software, attempts to gain unauthorized access to data, other electronic security breaches that could lead to disruptions in critical systems, the unauthorized release of protected information and the corruption or loss of data. The occurrence of such an attack could lead to financial losses and have a negative impact on our results of operations. We are not aware that any such breaches have occurred to date.

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.


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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 in this case 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 that was 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 located in Latimer, Le Flore, and Pittsburg Counties, Oklahoma. In July 2014, a second class certification hearing was held where, in addition to 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.

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.” The following table identifies the high and low closing sales prices per share of our common stock for the periods indicated:
 
2016
 
2015
Quarter
High
 
Low
 
High
 
Low
First
$
12.51

 
$
4.41

 
$
34.66

 
$
24.76

Second
$
17.81

 
$
8.44

 
$
36.23

 
$
26.79

Third
$
18.82

 
$
11.29

 
$
27.10

 
$
11.00

Fourth
$
28.11

 
$
16.44

 
$
19.53

 
$
10.60


On February 10, 2017, the closing sale price of our common stock, as reported by the NYSE, was $27.36 per share. On that date, there were approximately 836 holders of record of our common stock.

We have never declared any 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. Additionally, 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.

unt-2015123_chartx27737a03.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 2016, 2015, and 2014 activity.
 
As of and for the Year Ended December 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(In thousands except per share amounts)
 
Revenues
$
602,177

 
$
854,231

 
$
1,572,944

 
$
1,351,850

 
$
1,315,123

 
Net income (loss)
$
(135,624
)
(4) 
$
(1,037,361
)
(3) 
$
136,276

(2) 
$
184,746

 
$
23,176

(1) 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
 
Basic
$
(2.71
)
 
$
(21.12
)
 
$
2.80

 
$
3.83

 
$
0.48

 
Diluted
$
(2.71
)
 
$
(21.12
)
 
$
2.78

 
$
3.80

 
$
0.48

 
Total assets
$
2,479,303

(4) 
$
2,799,842

(3) 
$
4,463,473

(2) 
$
4,010,546

 
$
3,747,688

(1) 
Long-term debt (5)
$
800,917

 
$
918,995

 
$
801,908

 
$
633,852

 
$
702,927

 
Other long-term liabilities (6)
$
103,479

 
$
140,626

 
$
148,785

 
$
158,331

 
$