Unit Corporation Annual Report 2015

FY2015 Annual Report · Unit Corporation

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2015 Annual Report

Corporate
PROFILE

Unit Corporation is a diversified energy company engaged through its subsidiaries in the
exploration for and production of oil, natural gas, and natural gas liquids, the contract
drilling of onshore oil and natural gas wells, and the gathering and processing of natural gas.
Operations are mainly located in the Mid-Continent, Rocky Mountain, and Gulf Coast regions
with additional activity in the Permian and Appalachian Basins.

CASPER OFFICE

PITTSBURGH OFFICE

DENVER OFFICE

Mississippian Basin

Anadarko Basin

TULSA HEADQUARTERS

Arkoma Basin

OKLAHOMA CITY OFFICE

Permian Basin

Gulf Coast Basin
HOUSTON OFFICE

CONTRACT DRILLING

OIL & NATURAL GAS

MIDSTREAM

Year Ended December 31, ($ in thousands)

Financial
INFORMATION

2015

2014

2013

2012

2011

Total Revenues

854,231

1,572,944

1,351,850

1,315,123

1,207,503

Capital Expenditures 1

561,632

987,097

703,984

1,360,866

778,564

Total Assets

Long-Term Debt

Shareholders’ Equity

Total Capitalization

2,808,509

4,473,728

4,022,390

3,761,120

3,256,720

927,662

812,163

645,696

716,359

300,000

1,313,580

2,332,394

2,173,392

1,974,301

1,947,017

2,241,242

3,144,557

2,819,088

2,690,660

2,247,017

1 Capital expenditures (cash basis) including acquisitions.

To Our
SHAREHOLDERS

the current cycle ends they will be seeking additional
BOSS drilling rigs for their exploration programs.

In our midstream segment, we have been working to
increase the share of fee based margin and volume in
our contract mix. This strategy helped mitigate the
impact that dropping commodity prices had on this
segment’s cash flow. Volumes held up better than we
expected given the significant operator capital spending
cuts in 2015. We completed constructing our new Snow
Shoe Project and an extension of our Pittsburgh Mills
gathering system. Both systems are in the Marcellus dry
gas play and both are fee based projects.

As you can tell, the steps we have taken during this
down cycle have proven warranted and will continue
to require adjustment as we move forward. Our ability
to navigate through these cycles is one of Unit’s greatest
strengths. This cycle will end. When? Only time will tell.
In the meantime, we will continue to adjust to the evolving
conditions in preparation for the eventual recovery.

Larry D. Pinkston
CHIEF EXECUTIVE OFFICER AND PRESIDENT
February 25, 2016

We often talk about the up and down nature of the

oil and gas industry. Well, it was down in 2015,
and little improvement has been noted so far in 2016.
It now appears this downturn will be much longer in
duration and severity than most previous down cycles.
While we are pleased to close the books on 2015, our job
now is to focus on 2016 and beyond. That’s not to say
that 2015 was all bad or that we are not optimistic about
the future. Our task is clear. Recognize the issues we face
and deal with them in a purposeful manner. That is how
we have survived in this business for over 50 years.

Balance sheet preservation is a priority. For 2015, we
reduced our capital expenditures budget in excess
of 50% from 2014 levels. Our objective was to keep
our capital expenditures as close to anticipated cash
flow as possible. Late in the year, we reduced capital
expenditures by an additional 11% because of the
impact the continuing decline in commodity prices had
on our cash flow. We recently announced our capital
expenditure budget for 2016 will be a range of $161
million to $187 million, representing an additional 59%
to 65% reduction from 2015 levels. Additionally, we
have made numerous difficult decisions around G&A
cost reductions and activity levels. We cannot control
commodity prices, but we can exercise control of our
costs. This allows us to manage our liquidity.

Despite a year of extreme challenges, we experienced
some highpoints that continue to demonstrate lasting
value for our shareholders. In our oil and natural gas
segment, we attained year over year production growth
of 9%. This represented a new record annual production
for the segment. Additionally, we completed the first
three horizontal Wilcox wells. Two of the three wells
were located in our Gilly field and yielded strong results.
In addition, these wells are serving to set the stage for
further Wilcox horizontal development which we will
continue to execute as conditions improve.

In our contract drilling segment, there can be no
denying that it has been a difficult cycle. In November
2014, before commodity prices began to plunge,
there were 1,929 onshore drilling rigs working in the
United States. By the most recent count, that number
has fallen to 502 or a 74% reduction. Our drilling rig
utilization has experienced a similar decline. Against
this backdrop, we placed into service the last five of our
eight new BOSS drilling rigs. Operator feedback has
been very favorable, with several suggesting that when

Oil & Natural Gas Segment

During the year, we produced 20.0 MMBoe, 9% more
than
the 18.3 MMBoe produced during 2014.
Liquids (oil and NGLs) production represented 45% of
our total equivalent production for the year.

The substantial decline in commodity prices significantly
reduced our 2015 year-end reserves. At the end of
2015 our total proved reserves were 135.2 MMBoe, or
811.4 Bcfe, 24% less than 2014. Overall, 85% of our
estimated proved reserves are proved developed.
Estimated proved reserves were 12% oil, 28% natural
gas liquids (NGLs), and 60% natural gas. Although, the
reduction was substantial and resulted in our inability
to replace 2015 production, the hydrocarbons remain in
place to be developed when conditions improve.

Our 2015 oil and natural gas revenues decreased 48% to
$385.8 million. The price we received for our natural gas
averaged $2.63 per Mcf, a decrease of 33% from 2014.
Our average oil price decreased 43% from 2014 to $50.79
per barrel. Our NGLs price averaged $10.12 per barrel,
down 67% from 2014.

In our Wilcox play, in southeast Texas, in Polk, Tyler,
and Hardin Counties, production for the fourth quarter
averaged 88 MMcfe per day (11% oil, 31% NGLs), which
is a 25% increase over the fourth quarter of 2014, and
a 7% increase over the third quarter 2015. Two new
vertical Wilcox wells were completed during the quarter,
bringing the total for 2015 to 15 wells (three of which

pressure after 390 days on line. For 2016, we anticipate
completing
four horizontal Wilcox wells primarily
during the first quarter. Three of the wells have finished
drilling operations and have recently been fracture
stimulated. They are in the early stages of flow back.
The three wells did not encounter any significant drilling
issues and have an average lateral length of 5,666
feet. A fourth horizontal well is currently drilling and is
scheduled to be frac’d in the second quarter. In addition
to the new wells, we plan to complete approximately 8
behind pipe pay zones in vertical wells located primarily
in Gilly Field. The average cost for a behind pipe
recompletion is approximately $600,000 or about 10% of
the cost for a new horizontal well with an expected rate
of return in excess of 100% at current commodity pricing.
The combination of the four new horizontal wells and the
eight behind pipe recompletions is expected to generate
production growth of approximately 12% to 15% for the
Wilcox play in 2016. During this period of decreased well
activity, our primary focus is to build our well inventory
of drillable vertical and horizontal locations.

In our SOHOT area, located primarily in Grady County,
Oklahoma, production for the quarter averaged 44
MMcfe per day (28% oil, 21% NGLs), a 117% increase over
the fourth quarter 2014, and a 6% increase over the third
quarter 2015. Three horizontal operated Hoxbar wells
were completed during the quarter with two wells in the
Marchand bench and one well in the Medrano bench.
During the first quarter of 2016, we completed two new
Marchand sand wells that are in the early stages of flow
back. A third well has been drilled and is scheduled to be

9% YEAR OVER YEAR

PRODUCTION GROWTH

Produced 20.0 MMBoe during
2015, a company record.

are horizontal wells) with a 100% completion success
rate. Production from our three horizontal Wilcox wells
completed in the first half of 2015 continue to be strong.
The Parker 5H with 3,457’ of lateral (75% working interest)
is averaging approximately 13.9 MMcfe per day with 5,300
pounds of flowing tubing pressure after 330 days on
line. The Epstein 7H with 4,364’ of lateral (100% working
interest) is averaging approximately 10.8 MMcfe per day
with 2,700 pounds of flowing tubing pressure after 240
days online. The BP America 2H with 1,413’ of lateral
(100% working interest) is averaging approximately
1.6 MMcfe per day with 700 pounds of flowing tubing

fracture stimulated in mid-March. A fourth well is drilling
and will be completed in April. We anticipate being able
to continue to add core leasehold during 2016.

In the normal course of our operations, we have
continued to carry out our program of selling
certain non-core exploration and production assets.
in 2016, we completed various non-core oil
Early
and natural gas asset sales with total proceeds of
approximately $37.4 million.

Five

BOSS DRILLING RIGS CONSTRUCTED

Total of eight proprietary BOSS
rigs constructed to date.

Contract Drilling Segment

During the first half of 2015, we completed the
construction of five BOSS drilling rigs, all of which
were contracted and placed into service. This brings to
eight the number of BOSS drilling rigs we have built.
The BOSS drilling rig is a proprietary rig we designed and
built starting in 2013. It is a 1,500 horsepower AC drilling
rig that combines the best technological innovations
from high-tech drilling rig designs into a single unique
drilling rig that meets today’s demands. One of its
design features allows for a quick assembly substructure
which can be moved in less loads reducing the number
of permits needed to move the drilling rig to a new
location. The BOSS drilling rig provides us with the
leading design features needed to meet the increasing
technical demands of our customers.

The decline in commodity prices during 2015 also
resulted in a decline in the demand for the use of our
drilling rigs. During the third quarter, we were notified
of a customer’s intent to terminate early the contracts
on two BOSS drilling rigs, both of which contain early
termination penalties. The customer ultimately kept
one of the BOSS drilling rigs through its remaining
term, while we contracted the other BOSS drilling rig to a
third party operator. During the fourth quarter, we were
notified of a customer’s intent to terminate early the
contract on another of our BOSS drilling rigs, which was
subsequently laid down in January of 2016. We have
seven of our eight BOSS drilling rigs under contract.

For the year, our drilling revenues decreased 44% from
2014 to $265.7 million. Our average dayrates for the
year were $19,455, a 3% decrease from 2014, while

our average number of drilling rigs working was 34.7
compared to 75.4 for 2014.

At year-end, our drilling rig fleet consisted of 94 drilling
rigs up from 89 drilling rigs at the beginning of the year.
The increase was the result of the addition of the five
new BOSS drilling rigs. Of our 94 drilling rigs, 20 are
currently operating under contract.

Our rig fleet is located in varying geographic areas with
22 drilling rigs in our Rocky Mountain operations, 54 in
our Anadarko Basin operations, 12 in the Permian Basin
and six in our Gulf Coast operations. The maximum
depth capacities of our various drilling rigs range from
9,500 to 40,000 feet.

Over the years we have worked to strengthen our safety
program and 2015 reflected that effort as we achieved
our best safety performance in the company’s history.
Our safety program not only results in keeping our
employees safe but also leads to substantial savings in
our daily costs.

Butler County, Pennsylvania. This project includes a
seven-mile trunkline along with a related compressor
station. With the completion of this project we also gain
an additional outlet for the gas into NiSource pipeline.
The Clinton compressor station located in Butler County,
Pennsylvania was completed and became operational in
the fourth quarter of 2015. With the completion of this
expansion project, we now have the ability to connect
additional wells that are scheduled to be drilled in this
area in 2016.

Also
in the Appalachian area, we completed the
construction of our new fee-based gathering system,
Snow Shoe gathering system,
in Centre County,
Pennsylvania. This system consists of approximately
12 miles of gathering pipeline. The pipeline has been
installed and is now operational. We began flowing gas
on this pipeline in January 2016.

1,464

MILES OF PIPELINE

Midstream operations also include
3 gas treatment plants, 13 natural
gas processing plants, and 25 active
gathering systems.

Midstream Segment

For the year, processing volumes for our midstream
segment increased 13% to 182,684 Mcf per day, while
increased 11% to 353,771
gas gathering volumes
Mcf per day. Liquids sold volumes decreased 21% to
577,513 gallons per day from 2014. Revenues for 2015
for our midstream operations decreased 43% from
2014 to $202.8 million.

Our customer base consists mainly of independent
producers in Oklahoma, Texas, Kansas, Pennsylvania,
and West Virginia. We operate three gas treatment plants,
13 natural gas processing plants, 25 active gathering
systems, and approximately 1,464 miles of pipeline.

At our Hemphill Texas system with the completion
of the nine-mile pipeline that connects our Buffalo
Wallow gathering system to our Hemphill processing
facility, we began transporting Buffalo Wallow gathered
gas to our Hemphill facility for processing. At our
Hemphill processing facility, we have three operational
processing skids that provide approximately 135 MMcf
per day of processing capacity.

In central Oklahoma at our Perkins processing facility,
we completed the upgrade of our processing facility
which increased our total processing capacity from 20
MMcf per day to 27 MMcf per day. These improvements
consist of processing plant upgrades along with projects
to improve recoveries at this facility. During 2015, we
connected 11 new wells to this system from several
producers.

Also in central Oklahoma, at our Minco processing
facility, we completed upgrades to this facility which
improved our processing capacity and allowed us to
gather and process additional liquid rich gas from third-
party producers. With this upgrade the total processing
capacity of this system was increased to approximately
15 MMcf per day.

In the Mississippian play in north central Oklahoma, we
completed the upgrade of our Bellmon gathering system
along with the installation of additional compressors.
This will allow us to receive additional volume from
third-party producers in the area. We connected 40
new wells to this system from several producers during
2015. At this processing facility we have two operational
processing skids that provide total processing capacity
of approximately 90 MMcf per day.

In the Appalachian region, we completed the northern
expansion of the Pittsburgh Mills gathering system into

Operational
HIGHLIGHTS

Year Ended December 31, ($ in thousands except average price amounts)

2015

2014

2013

2012

2011

OIL AND NATURAL GAS OPERATIONS DATA:

Proved Oil And Natural Gas Reserves Discounted
at 10% (Before Income Taxes)

Proved Oil And Natural Gas Reserves Discounted
at 10% (After Income Taxes)

Total Estimated Proved Reserves:

Natural Gas (MMcf)

Oil (MBbl)

Natural Gas Liquids (MBbl)

Equivalent (MBoe)

Production:

Natural Gas (MMcf)

Oil (MBbl)

Natural Gas Liquids (MBbl)

Equivalent (MBoe)

Average Price:

Natural Gas (Per Mcf)

Oil (Per Bbl)

Natural Gas Liquids (Per Bbl)

Equivalent (Boe)

Well Data:

Wells Drilled

Wells Completed

Success Rate

690,693

$ 2,099,789

$ 1,791,903

$ 1,475,792

1,578,422

589,486

$ 1,435,744

$ 1,225,976

$ 1,079,956

1,087,909

484,868

16,735

37,687

135,233

65,546

3,783

5,274

19,982

646,961

22,667

48,529

179,023

58,854

3,844

4,628

18,281

581,784

21,765

41,205

159,934

56,757

3,360

3,914

16,734

555,647

21,998

35,166

149,772

48,930

3,279

2,796

14,230

2.63

50.79

10.12

20.92

3.92

89.43

30.95

39.25

3.32

95.06

31.79

37.77

3.37

92.60

31.58

39.14

442,135

20,255

22,087

116,031

44,104

2,511

2,239

12,101

4.26

87.18

43.64

41.71

97%

186

181

97%

149

143

96%

171

169

99%

160

144

90%

2015

2014

2013

2012

2011

PRODUCING WELL COUNT:

GROSS

NET

GROSS

NET

GROSS

NET

GROSS

NET

GROSS

NET

Natural Gas

Oil

Total

6,234

1,627

7,861

2,169

650

2,819

6,369

1,752

8,121

2,184

663

2,847

6,705

2,991

9,696

2,182

599

2,781

6,986

2,937

9,923

2,213

564

2,777

5,915

2,759

8,674

1,541

460

2,001

CONTRACT DRILLING OPERATIONS DATA:

Number of Drilling Rigs Available for Use at Year End

Wells Drilled

Total Footage Drilled (Feet In 1,000’s)

Average Number of Drilling Rigs Utilized

MID-STREAM OPERATIONS DATA:

Natural Gas Gathered (Mcf/Day)

Natural Gas Processed (Mcf/Day)

Liquids Sold (Gallons/Day)

2015

2014

2013

2012

2011

894

12,551

75.4

319,348

161,282

733,406

121

793

10,578

65.0

309,554

140,584

543,602

127

773

10,551

73.9

250,290

133,987

542,578

127

742

9,749

76.1

188,569

92,940

412,064

516

7,237

34.7

353,771

182,684

577,513

FORM 10-K

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, 2015

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
(State or other jurisdiction of incorporation or organization)

73-1283193
(I.R.S. Employer Identification No.)

7130 South Lewis, Suite 1000
Tulsa, Oklahoma
(Address of principal executive offices)

74136

(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

Rights to Purchase Series A Participating
Cumulative Preferred Stock

NYSE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Securities registered pursuant to Section 12(g) of the Act: None

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 [x]

Accelerated filer [ ]

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, 2015, 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, 2015) held by non-affiliates was approximately $726,406,732. 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
Common Stock, $0.20 par value per share .........................................................

Outstanding at February 12, 2016
51,022,722 shares

DOCUMENTS INCORPORATED BY REFERENCE

Document
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 4, 2016. The Proxy Statement will be filed within 120 days after the
end of the fiscal year to which this report relates.

Parts Into Which Incorporated
Part III

Exhibit Index—See Page 121

FORM 10-K
UNIT CORPORATION

TABLE OF CONTENTS

PART I

Item 1.

Business .......................................................................................................................................................

Item 1A.

Risk Factors .................................................................................................................................................

Item 1B.

Unresolved Staff Comments ........................................................................................................................

Item 2.

Item 3.

Item 4.

Item 5.

Item 6.

Item 7.

Properties .....................................................................................................................................................

Legal Proceedings........................................................................................................................................

Mine Safety Disclosures ..............................................................................................................................

PART II

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

Selected Financial Data................................................................................................................................

Management’s Discussion and Analysis of Financial Condition and Results of Operation........................

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk......................................................................

Item 8.

Item 9.

Financial Statements and Supplementary Data............................................................................................

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................

Item 9A.

Controls and Procedures ..............................................................................................................................

Item 9B.

Other Information ........................................................................................................................................

PART III

Item 10.

Directors, Executive Officers, and Corporate Governance..........................................................................

Item 11.

Executive Compensation .............................................................................................................................

Item 12.

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

Item 13.

Certain Relationships and Related Transactions, and Director Independence ............................................

Item 14.

Principal Accountant Fees and Services ......................................................................................................

PART IV

Page

111

112

113

114

Exhibits and Financial Statement Schedules ...............................................................................................
Item 15.
Signatures .............................................................................................................................................................................
Exhibit Index ........................................................................................................................................................................

115

120

121

The following are explanations of some of the terms used in this report.

DEFINITIONS

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, 2015

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 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136; 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 12, 2016:

Oil and Natural Gas

Completed gross wells in which we own an interest..........................................................................................

6,781

Contract Drilling

Number of drilling rigs available for use............................................................................................................

Mid-Stream

Number of natural gas treatment plants we own ................................................................................................

Number of processing plants we own.................................................................................................................

Number of natural gas gathering systems we own .............................................................................................

2015 SEGMENT OPERATIONS HIGHLIGHTS

Oil and Natural Gas

• Exceeded annual production guidance with total production of 20.0 MMBoe or a 9% increase over 2014.

•

Successfully completed three horizontal Wilcox wells with very strong results from recent well completions.

Contract Drilling

•

Placed five new BOSS drilling rigs into service during the year.

Sold 31 older, lower horsepower mechanical and SCR drilling rigs.

• Achieved the best safety performance record in history of company.

Mid-Stream

• Gas gathered volumes increased 11% over 2014.

• Gas processed volumes increased 13% over 2014.

•

102 new wells were connected to our gathering and processing facilities.

• Completed construction of the new fee-based Snow Shoe gathering system in Centre County, Pennsylvania. It

became operational in January 2016.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 16 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.

OIL AND NATURAL GAS

General. We began to develop our exploration and production operations in 1979. Today, our wholly owned subsidiary,

Unit Petroleum Company, conducts our exploration and production activities. Our producing oil and natural gas properties,
unproved properties, and related assets are in the following locations:

Division

Location
Western and Southern Texas, Colorado, Wyoming, Montana, North Dakota, New Mexico,

West division............................
East division............................. East Texas, Eastern Oklahoma, Arkansas, and Northern Louisiana
Central division........................ Western Oklahoma, Texas Panhandle, and Kansas

Southern Louisiana, and Mississippi

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, 2015:

Our Divisions/Area
West division.........
East division ..........
Central division .....
Total ...............

Number
of
Gross
Wells

1,370

1,389

5,131

7,890

Number
of Net
Wells

482.44

468.37

1,879.31

2,830.12

Number
of Gross
Wells in
Process

Number
of Net
Wells in
Process

—

3.02

—

3.02

2015 Average
Net Daily Production

Natural
Gas
(Mcf)

48,759

18,758

112,061

179,578

Oil
(Bbls)

1,864

8,472

10,365

NGLs (Bbls)
4,220

10,212

14,449

As of December 31, 2015, 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 12
operated gross vertical wells (average working interest 90%) in 2015 and three operated gross horizontal wells (average
working interest 92%) in 2015. All 15 wells were completed as gas/condensate producers. Annual production in our Wilcox
play averaged 77.4 MMcfe per day (11% oil, 31% NGLs, 58% natural gas) which is an increase of approximately 19% as
compared to 2014. We averaged 1.4 Unit drilling rigs operating during 2015 and currently plan to use one Unit drilling rig
during 2016. We anticipate completing approximately four horizontal Wilcox wells primarily in the first quarter 2016.
Additional wells may be drilled later in the year depending on commodity prices. In addition, we plan to complete
approximately eight to 10 behind pipe gas and liquids zones located primarily in the Wilcox Gilly Field.

Central division. SOHOT (Southern Oklahoma Hoxbar Oil Trend) is a play located primarily in Grady County,
Oklahoma that we first drilled in 2013. The producing horizon is named the Hoxbar which is an interval that contains several
potential oil and gas sands which are generally 50 to 100 feet thick. During 2015, we completed 15 Hoxbar horizontal wells
focused primarily on two Hoxbar benches named the Marchand oil zone and the Medrano gas liquids zone. Five of the wells
were completed in the Hoxbar “Marchand” zone and 10 wells were completed in the Hoxbar “Medrano” zone. Production
during the fourth quarter 2015 averaged 2,047 barrels of oil per day, 1,529 barrels of NGLs per day, and 22.1 MMcf of natural
gas per day, which is a 117% increase over the fourth quarter 2014. The average working interest for the 15 wells is 86%.
During 2015, we averaged approximately 1.7 Unit drilling rigs in SOHOT. For 2016, our current plan is to drill with one
drilling rig through the end of the first quarter at which time we will release the drilling rig. Additional wells may be drilled
later in the year depending on commodity prices.

In the Texas Panhandle District, which consists primarily of Granite Wash (GW) wells, daily production for 2015

averaged approximately 167 MMcfe per day (13% oil, 38% NGLs) which is an increase of 5% over 2014. We had first sales on
nine horizontal GW wells, primarily in the first quarter of 2015 having an average working interest of 73%. For 2015, we

averaged 0.3 Unit drilling rigs in the GW. For 2016, we anticipate drilling one horizontal well during the first quarter.
Additional wells may be drilled later in the year depending on commodity prices.

In our Mississippian play in south central Kansas, the average daily production for 2015 was approximately 1,885 Boe per
day (64% oil and 12% NGLs) which is an increase of 23% as compared to 2014. We had first sales on three operated horizontal
Mississippian wells during the first quarter 2015 with a 100% average working interest. During 2015, we averaged 0.4 Unit
drilling rigs in the Mississippian play. One or two Mississippian wells may be drilled in late 2016 depending on commodity
prices.

In the Marmaton horizontal oil play in Beaver County, Oklahoma, we had first sales on three horizontal wells during the
first quarter of 2015 with an average working interest of 70%. The daily average production rate for 2015 was approximately
2,500 Boe per day (57% oil and 16% NGLs) which is a decrease of 37% as compared to 2014. We do not anticipate drilling any
new wells in the play during 2016.

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.

Dispositions. In August 2013, we sold some of our Bakken property interests. The proceeds, net of related expenses,
were $57.1 million. In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million,
$33.1 million, and $1.9 million for 2013, 2014, and 2015, respectively. Proceeds from these dispositions reduced the net book
value of our full cost pool with no gain or loss recognized.

We determined the value of certain 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)
and $114.4 million (in 2015) 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. 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) in 2015 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.

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,

2015

2014

2013

Gross

Net

Gross

Net

Gross

Net

Wells drilled:
Development:

Oil:

West division....................

East division.....................

Central division................

Total oil..........................

Natural gas:

West division....................

East division.....................
Central division................

Total natural gas.............

Dry:

West division....................

East division.....................

Central division................

Total dry.........................

Total development ....

Exploratory:

Oil:

West division....................

East division.....................

Central division................

Total oil..........................

Natural gas:

West division....................
East division.....................

Central division................

Total natural gas.............

Dry:

West division....................

East division.....................

Central division................

Total dry.........................

Total exploratory.......

Total wells drilled

—

—
18

—

0.66

—

8.12

8.78

13.50

—
11.50

25.00

1.00

—

0.21

1.21

34.99

—

115

119

—
49

—

0.37

—

74.07

74.44

6.09

—
31.91

38.00

0.80

—

1.03

1.83

—

1
37

—

179

114.27

147

—

0.93

4.80

—

4.80

1.00

—

1.00

6.73

—

34.99

186

121.00

149

0.08

—

51.33

51.41

8.60

—
26.00

34.60

1.35

—

1.78

3.13

89.14

—

2.00

—

2.00

—

2.00

91.14

Wells producing or capable of

producing:

Oil:

West division .................

East division ..................

Central division .............

Total oil................

Natural gas:

West division .................

East division ..................

Central division .............

Total natural gas...

Total..............

2015

Year Ended December 31,
2014 (1)

2013

Gross

Net

Gross

Net

Gross

Net

692

907

1,627

659

1,358

4,217

6,234

7,861

149.34

1.79

498.75

649.88

325.57

466.22

1,376.94

2,168.73

2,818.61

713

997

1,752

703

1,401

4,265

6,369

8,121

164.25

1.91

497.10

663.26

326.64

466.79

1,390.05

2,183.48

2,846.74

2,058

891

2,991

1,004

1,435

4,266

6,705

9,696

170.49

1.91

426.75

599.15

326.79

472.68

1,382.62

2,182.09

2,781.24

_________________________
(1) During 2014, we had divestitures of 1,716 gross (37.31 net) wells.

As of February 12, 2016, we were drilling or participating in six gross (2.92 net) wells started during 2016.

Cost incurred for development drilling includes $58.6 million, $199.7 million, and $136.7 million in 2015, 2014, and

2013, respectively, to develop previously booked proved undeveloped oil and natural gas reserves.

The following table summarizes our leasehold acreage at December 31, 2015:

West division................................

East division.................................

Central division............................

Total......................................

Developed

Year Ended December 31, 2015
Undeveloped

Total

Gross
271,564

200,547

910,356

1,382,467

Net
85,851

86,988

373,996

546,835

Gross
134,701

22,003

145,954

302,658

Net (1)

86,085

8,770

100,205

195,060

Gross
406,265

222,550

1,056,310

1,685,125

Net
171,936

95,758

474,201

741,895

_________________________
(1) Approximately 69% (West – 57%; East – 88%; and Central – 78%) of the net undeveloped acres are covered by leases that will expire in the years 2016—

2018 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.

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:

Average sales price per barrel of oil produced:

Price before derivatives ..........................................................................
Effect of derivatives................................................................................
Price including derivatives .....................................................................

Average sales price per barrel of NGLs produced:

Price before derivatives ..........................................................................

Effect of derivatives................................................................................

Price including derivatives .....................................................................

Average sales price per Mcf of natural gas produced:

Price before derivatives ..........................................................................

Effect of derivatives................................................................................
Price including derivatives .....................................................................

Year Ended December 31,

2015

2014

2013

45.04

5.75

50.79

10.12

—

10.12

2.25

0.38
2.63

89.32

0.11

89.43

30.95

—

30.95

4.03
(0.11)
3.92

95.18
(0.12)
95.06

31.79

—

31.79

3.33
(0.01)
3.32

Oil production (MBbls):

West division

Jazz field..........................................................................................
All other west division fields...........................................................
Total west division.................................................................
East division............................................................................................
Central division:

Mendota field...................................................................................
All other central division fields .......................................................
Total central division..............................................................
Total oil production (MBbls)..........................................

NGLs production (MBbls):

West division

Mendota field...................................................................................
All other central division fields .......................................................
Total central division..............................................................
Total NGLs production (MBbls) ....................................

Natural gas production (MMcf):

West division

Mendota field...................................................................................
All other central division fields .......................................................
Total central division..............................................................
Total natural gas production (MMcf) .............................

Total production (MBoe):

West division

Mendota field...................................................................................
All other central division fields .......................................................
Total central division..............................................................
Total production (MBoe)................................................
Average production cost per equivalent Bbl (1)..............................................

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

Year Ended December 31,

2015

2014

2013

422
258
680
11

343
2,749
3,092
3,783

1,275
266
1,541
6

1,127
2,600
3,727
5,274

2,423
15,374
17,797
6,846

1,320
39,583
40,903
65,546

4,120
1,067
5,187
1,158

2,790
10,847
13,637
19,982
7.06

377
256
633
8

407
2,796
3,203
3,844

989
235
1,224
6

1,117
2,281
3,398
4,628

2,066
13,882
15,948
7,719

7,555
27,632
35,187
58,854

3,431
1,084
4,515
1,301

2,783
9,682
12,465
18,281
7.70

312
378
690
16

412
2,242
2,654
3,360

788
205
993
24

1,050
1,847
2,897
3,914

1,471
11,591
13,062
9,401

9,138
25,156
34,294
56,757

2,572
1,288
3,860
1,607

2,985
8,282
11,267
16,734
7.63

Our Jazz Wilcox field in South Texas, which includes Gilly, Segno, and Wildwood prospects and several smaller

prospects, contained 24%, 17%, and 11% of our total proved reserves in 2015, 2014, and 2013, respectively, expressed on an oil
equivalent barrels basis. Our Mendota field, located in the Granite Wash play in the Texas Panhandle, includes 14%, 17%, and
18%, respectively of our total proved reserves in 2015, 2014, and 2013, 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:

Proved developed:

West division...............................................................

East division ................................................................

Central division ...........................................................
Total proved developed........................................

Proved undeveloped:

West division...............................................................

East division ................................................................

Central division ...........................................................

Total proved undeveloped....................................

Total proved ....................................................

Year Ended December 31, 2015

Oil
(MBbls)

NGLs (MBbls)

Natural
Gas
(MMcf)

Total
Proved
Reserves
(MBoe)

4,051

10,585
14,679

424

—

1,632

2,056

16,735

10,216

20,944
31,218

790

—

5,679

6,469

37,687

120,184

73,480

222,731
416,395

10,666

4,377

53,430

68,473

34,298

12,347

68,651
115,296

2,992

729

16,216

19,937

484,868

135,233

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 reserve and income projections prepared by us as of December 31, 2015 and comprised 79% of the total
proved developed discounted future net income and 81% 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 the 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 correctness 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.

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 2015 continuing education hours, Mr. Paradiso attended 2 hours of formalized training
during the 2015 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 31.5 hours of formalized in-house training
during 2015 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 36 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 David Morrill.

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. Morrill received a Bachelor of Science degree in Natural Gas Engineering from Texas A&I University in 1970 and

has spent 35 of his 40 years in the industry directly involved in reserve evaluation and appraisals, acquisitions, prospect
reviews, and field studies. Included in this time were eight years working for the petroleum consulting firm Keplinger and
Associates. He joined Unit in 2006 and since that time has shared responsibility for preparation of the company's reserve report.
Mr. Morrill is a registered professional engineer in the State of Oklahoma and a member of the Society of Petroleum Evaluation
Engineers (SPEE) and SPE.

As part of the continuing education requirement for maintaining their professional licenses Mr. Mitchell and Mr. Morrill

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

seen in a well penetration unless geosciences, engineering or performance data and reliable technology establishes a lower
contact with reasonable certainty.

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 expenditure 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 any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such 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, 2015, we had 65 gross proved undeveloped wells all of which we

plan to develop within five years of initial disclosure at a net estimated cost of approximately $156.8 million. The future
estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United States for
the years 2016—2020, as disclosed in our December 31, 2015 oil and natural gas reserve report, are shown below:

Year
2016..........................................................................
2017..........................................................................
2018..........................................................................
2019..........................................................................
2020..........................................................................

Number of Gross Wells Planned

Estimated Development Cost
(In millions)

—

19.3

66.5

65.0

6.0

—

156.8

Our proved undeveloped reserves reported at December 31, 2015 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 PUD reserves during
2015:

Proved undeveloped reserves, January 1, 2015..................
Extensions and discoveries.................................................
Converted to developed......................................................
Revisions of previous estimates .........................................
Sales of reserves .................................................................
Proved undeveloped reserves, December 31, 2015............

Oil
(MMBbls)

NGLs
(MMBbls)

Natural Gas
(Bcf)

Total
(MMBoe)

5.2

0.1
(0.7)
(2.6)
—

2.0

12.7

0.6
(1.1)
(5.7)
—

6.5

146.1

8.7
(15.6)
(70.7)
—

68.5

42.2

2.2
(4.4)
(20.1)
—

19.9

During 2015, we converted 19 proved undeveloped wells into proved developed wells at a cost of approximately $58.6
million. The downward revision to previous estimates were due to a number of factors including the removal of PUDs 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, 2015, 2014, and 2013, 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 2015, sales to Sunoco Logistics and Valero Energy Corporation accounted for 19% and 15% of our

oil and natural gas revenues, respectively. There was no other company that accounted for more than 10% of our oil and natural
gas revenues. During 2015, our mid-stream segment purchased $57.6 million of our natural gas and NGLs production and
provided gathering and transportation services of $7.6 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 2014 and 2013, we eliminated intercompany revenues of $89.6 million and $91.0 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, Wyoming, and North Dakota. Until October 31, 2015, our drilling operations in
Texas was conducted under Unit Drilling Texas, a subsidiary of Unit Drilling Company. Effective October 31, 2015, that
subsidiary was merged into Unit Drilling Company.

The following table identifies certain information concerning our contract drilling operations:

Number of drilling rigs available for use at year end ....................................

Average number of drilling rigs owned during year......................................

Average number of drilling rigs utilized........................................................
Utilization rate (1) ...........................................................................................
Average revenue per day (2)............................................................................
Total footage drilled (feet in 1,000’s) ............................................................

Number of wells drilled .................................................................................

Year Ended December 31,

2015

2014

2013

94.0

92.6

34.7

89.0

118.8

75.4

121.0

125.4

65.0

38%

63%

52%

20,950

7,237

516

17,318

12,551

894

17,486

10,578

793

_________________________
(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 operations 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, 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, 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 top drives, iron roughnecks, automated catwalks, skidding systems, large air
compressors, trucks, and other support equipment.

The maximum depth capacities of our various drilling rigs range from 9,500 to 40,000 feet to cover a wide range of our

customers drilling requirements. In 2015, 81 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 12,

2016:

Divisions
Mid-Continent ....................................................................
Panhandle (1) .......................................................................
Gulf Coast (1).......................................................................
Rocky Mountain.................................................................

Totals...........................................................................

Contracted
Rigs

Non-
Contracted
Rigs

Total
Rigs

Average
Rated
Drilling
Depth
(ft)

16,867

14,900

21,000

20,000

17,798

_________________________
(1)

In 2016, these divisions will be consolidated into the Mid-Continent division.

The cyclical nature of the drilling business is best reflected in drilling rig utilization rates. Drilling rig utilization was

relatively flat throughout 2013 averaging 65 drilling rigs operating for the year. Then 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 reflects the
beginning of the current downward market trend with a precipitous decline of 50 drilling rigs through the end of the first quarter
of 2015 where we slowed to 31 operating drilling rigs. This level of utilization continued through August with the weakening of
commodity prices through the end of the year. At the end of 2015, our active drilling rig count was 26.

Mid-Continent, Woodward, and Panhandle. We have long held a strong position and market presence in the mid-
continent area of Oklahoma and the Texas Panhandle. This area is commonly referred to as the Anadarko Basin, which also
encompasses portions of Kansas. Historically, the Anadarko Basin has been known as a gas producing area, but it is also rich in
oil and NGLs production. During the last several years operators have focused their operations in this basin on the Cana
Woodford, Granite Wash, Southern Oklahoma Hoxbar Oil Trend (SOHOT), Cleveland, Tonkawa, Marmaton, and Mississippian
13

horizontal plays. Typically, three of our divisions work in this basin. During 2015, our Mid-Continent and Panhandle divisions
averaged 14.2 and 4.1 drilling rigs operating, respectively. We have consolidated our Woodward division into the Panhandle
division with the decline of drilling rig activity in this current market. At the end of 2015, these two divisions had 11 drilling
rigs operating in Oklahoma and the Texas Panhandle. Additionally, two Mid-Continent drilling rigs were operating in the
Permian Basin at the end of year.

Gulf Coast. Our Gulf Coast division provides drilling rigs to the onshore areas of Texas and Louisiana. During 2015, the

Gulf Coast division averaged 4.0 drilling rigs operating. The Gulf Coast had one drilling rig working in East Texas and two
drilling rigs operating in the Permian Basin at the end of 2015.

Rocky Mountains. Our Rocky Mountain division covers several states, including 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 10.0 drilling rigs during 2015. We had four drilling rigs operating in the Pinedale Anticline of western
Wyoming, four drilling rigs operating in the Bakken Shale of North Dakota, and two drilling rigs operating in the Niobrara play
of eastern Colorado at the end of 2015.

In 2016, due to the current market conditions, we will further consolidate the divisions. Our Panhandle and Gulf Coast
divisions will be consolidated into the Mid-Continent. We will then have two divisions, Mid-Continent and Rocky Mountain.

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 2015, 2014, and 2013 was 38%, 63%, and 52%,
respectively.

The following table shows the average number of our drilling rigs working by quarter for the years indicated:

First quarter....................................................................................................

Second quarter ...............................................................................................

Third quarter ..................................................................................................

Fourth quarter.................................................................................................

2015

2014

2013

50.1

30.7

31.2

27.2

67.9

73.5

79.1

80.9

66.3

65.2

63.5

65.0

Drilling Rig Fleet. The following table summarizes the changes made to our drilling rig fleet in 2015. A more complete

discussion of the changes follows the table:

Drilling rigs available for use at December 31, 2014 ...........................................................................................
Drilling rigs sold (1) ...............................................................................................................................................
Drilling rigs constructed........................................................................................................................................

Total drilling rigs available for use at December 31, 2015...................................................................................

—

_________________________
(1) During 2015, we sold 31 drilling rigs previously removed from service in December 2014.

Dispositions, Acquisitions, and Construction. During 2013, we sold four of our 2,000 horsepower electric drilling rigs

and one 3,000 horsepower electric drilling rigs. All of these sales were to unaffiliated third-parties.

During the first quarter of 2014. we sold four additional 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

resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs
and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During
the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of
those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. Some of
the equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held
for sale. The net book value of those assets is $0.6 million.

During the first half of 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.
The long lead time components for three additional BOSS drilling rigs were ordered in 2014 in anticipation for future demand
of the BOSS drilling rigs. However, with the decline in the demand in the drilling market, many of these long lead time
components were either postponed for later delivery or canceled altogether. Currently, we do not have any contracts to build
new BOSS drilling rigs.

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
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 2015, 2014, or 2013. 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 three years and the rates can either be fixed throughout the term or allow for periodic adjustments.

Customers. During 2015, QEP Resources, Inc. was our largest drilling customer accounting for approximately 25% of

our total contract drilling revenues. Our work for this customer was under multiple contracts and our business was not
substantially dependent on any of these individual contracts. 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 2015, 2014, and

2013, our contract drilling segment drilled 38, 134, and 105 wells, respectively, for our oil and natural gas segment, or 7%,
15%, and 13%, 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. By providing
drilling services for the oil and natural gas segment, we eliminated revenue of $22.1 million, $89.5 million, and $64.3 million
during 2015, 2014, and 2013, respectively, from our contract drilling segment and eliminated the associated operating expense
of $18.3 million, $62.4 million, and $46.9 million during 2015, 2014, and 2013, respectively, yielding $3.8 million, $27.1
million, and $17.4 million during 2015, 2014, and 2013, 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 1,464 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:

Gas gathered—Mcf/day .................................................................................

Gas processed—Mcf/day ...............................................................................

NGLs sold—gallons/day................................................................................

Year Ended December 31,

2015

2014

2013

353,771

182,684

577,513

319,348

161,282

733,406

309,554

140,584

543,602

Dispositions and Acquisitions. This segment did not have any significant dispositions or acquisitions during 2013, 2014,

or 2015.

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.

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, 2015, 68% of our mid-stream segment’s total volumes and
65% 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, 2015, 32% of our mid-stream segment’s total volumes and 35% 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 2015, ONEOK Partners, L.P., Tenaska Resources, LLC, and Laclede Group, Inc. accounted for
approximately 29%, 18%, and 12%, 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 2015, 2014, and 2013 this segment
purchased $57.6 million, $80.9 million, and $83.0 million, respectively, of our oil and natural gas segment's natural gas and
NGLs production, and provided gathering and transportation services of $7.6 million, $8.7 million, and $8.0 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:

Quarter
2013

First........................................
Second ...................................
Third ......................................
Fourth ....................................

$
$
$
$

2014

First........................................ $
Second ...................................
$
Third ......................................
$

Fourth ....................................

2015

First........................................ $
Second ...................................
$

Third ......................................

Fourth ....................................

Oil Price per Bbl

NGLs Price per Bbl

Natural Gas Price per Mcf

High

Low

High

Low

High

Low

93.89
92.85
104.25
97.34

98.09

102.62
98.95

82.30

46.70

54.37

49.02

42.21

$
$
$
$

$
$

90.80
89.97
101.70
91.15

90.51

98.76
90.70

54.22

43.22

49.28

40.36

33.29

$
$
$
$

$
$

37.97
32.17
33.14
36.33

41.62

35.45
31.08

29.02

18.90

15.41

9.49

12.81

$
$
$
$

$
$

33.14
28.94
24.78
31.92

36.75

25.70
29.32

19.49

1.60

10.21

7.81

9.03

$
$
$
$

$
$

3.20
4.04
3.33
3.36

5.00

4.38
3.88

3.96

2.85

2.50

2.51

2.12

$
$
$
$

$
$

3.04
3.73
2.79
3.08

4.25

4.15
3.36

3.31

2.30

2.11

2.17

1.64

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. Prices after 2015 year-end have declined below the price at December 31, 2015. 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.

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 15 oil and gas limited partnerships. Two were formed for
investment by third parties and 13 (the employee partnerships) 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. The non-employee partnerships
were formed in 1984 and two in 1986. Effective December 31, 2014, the 1984 partnership was dissolved. Employee
partnerships were formed for each year beginning with 1984 and ending with 2011.

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 12, 2016, we had approximately 671 employees in our contract drilling segment, 290 employees in our oil

and natural gas segment, 140 employees in our mid-stream segment, and 78 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
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
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 increasingly stringent 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 definition of the “waters of the United States,”

which rules has been stayed by courts pending conformity with the definition U.S. Supreme Court previously established.

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.
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. In September and November 2013, the EPA proposed further revisions to record keeping and reporting
requirements, which have not yet been finalized. The adoption and implementation of any regulations imposing reporting
obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to
reduce emissions of GHGs associated with our operations or could adversely affect demand for the crude oil we gather,
transport, store or otherwise handle in connection with our services. In addition, both President Obama and the Administrator of
the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework
for a clean energy economy, with the Obama Administration supporting an emission allowance system. Past proposed
legislation in Congress has included an economy wide cap and trade program to reduce U.S. greenhouse gas emissions. Some
states are also looking at similar types of laws and regulations.

The EPA in 2015 proposed rules to reduce methane and ozone-forming VOC emissions for new and modified sources in

the oil and gas sector.

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. The EPA is studying the potential
environmental impacts of hydraulic fracturing, including the impact on drinking water sources and public health, and a
committee of the U.S. House of Representatives has been conducting an investigation of hydraulic fracturing practices.
Legislation has 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 and if enacted, it would likely be subject to a Presidential
veto. 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
21

certain circumstances. 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.

Other; Compliance Costs. We cannot predict future legislation or regulations It is possible that such 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;

the number of wells we plan to drill or rework;

prices for oil, NGLs, and natural gas;

demand for oil, NGLs, and natural gas;

our exploration and drilling prospects;

the estimates of our proved oil, NGLs, and natural gas reserves;

oil, NGLs, and natural gas reserve potential;

development and infill drilling potential;

expansion and other development trends of the oil and natural gas industry;

our business strategy;

our plans to maintain or increase production of oil, NGLs, and natural gas;

•

the number of gathering systems and processing plants we plan to construct or acquire;

volumes and prices for natural gas gathered and processed;

expansion and growth of our business and operations;

demand for our drilling rigs and drilling rig rates;

our belief that the final outcome of our legal proceedings will not materially affect our financial results;

our ability to timely secure third-party services used in completing our wells;

our ability to transport or convey our oil, NGLs, or natural gas production to established pipeline systems;

impact of federal and state legislative and regulatory actions impacting 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;

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;

decreases or increases in commodity prices; 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.

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 2015 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 $520,000 per month ($6.2 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 $303,000 per
month ($3.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs price,
without the effect of derivatives, would have a $419,000 per month ($5.0 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 2015, 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 24%
and 40% of our 2015 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.

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.

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

have, a certain amount of indebtedness. At December 31, 2015, we had $281.0 million of outstanding long-term debt under our
credit agreement and the amount of the Notes, net of unamortized discount, was $646.7 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.

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 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 would further depress the level of exploration and
production activity. This, in turn, would likely result in further declines in the demand for our drilling services and would have
an adverse effect on our contract drilling revenues, cash flows, and profitability. As a result, the future demand for our drilling
services is uncertain.

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

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

We have experienced and may continue to experience substantial capital needs for our operations. We have $646.7
million of indebtedness outstanding (net of unamortized discount) under the senior subordinated notes we have issued to date
and in addition, have the right to borrow up to $500.0 million under our credit agreement. As of February 12, 2016, we had
$262.9 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 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.
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 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.

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.

Our continued oil and natural gas segment and mid-stream segment success and the success of 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.

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.

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

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 2015, sales to Sunoco Logistics and Valero Energy Corporation accounted for 19% and 15% of our oil and natural

gas revenues, respectively. QEP Resources, Inc. was our largest drilling customer accounting for approximately 25% of our
total contract drilling revenues. And for our mid-stream segment, ONEOK Partners, L.P., Tenaska Resources, LLC, and Laclede
Group, Inc. accounted for approximately 29%, 18%, and 12%, 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.

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.

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
(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
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, 2015, we had 65 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. At the latest redetermination in October 2015, the lenders reduced our borrowing base from $725.0 million to
$550.0 million primarily due to lower commodity prices. Continued lower commodity prices and reductions in our oil and gas
drilling program could lead to further reduction in our borrowing base amount.

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.

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.

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.

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 sales prices per share of our common stock for the periods indicated:

Quarter
First..................................................................................... $
Second ................................................................................
$

Third ...................................................................................

Fourth .................................................................................

2015

2014

High

Low

High

Low

34.66

36.23

27.10

19.53

24.76

26.79

11.00

10.60

65.63

68.88

70.36

59.68

48.47

61.40

57.85

28.24

On February 12, 2016, the closing sale price of our common stock, as reported by the NYSE, was $6.99 per share. On

that date, there were approximately 866 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.

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

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 2015, 2014, and
2013 activity.

As of and for the Year Ended December 31,

2015

2014

2013

2012

2011

Revenues(1) ...........................................
Net income (loss) .................................
Net income (loss) per common share:

854,231
$
$ (1,037,361) (4) $

$ 1,572,944

(In thousands except per share amounts)
$ 1,351,850
184,746

136,276 (3) $

$ 1,315,123
$

23,176 (2) $

$ 1,207,503
195,867

Basic.............................................. $
Diluted...........................................
$
3.80
$ 2,808,509 (4) $ 4,473,728 (3) $ 4,022,390
645,696
$

812,163

927,662

(21.12)

2.80

2.78

3.83

0.48

4.11

0.48

$
4.08
$ 3,761,120 (2) $ 3,256,720
300,000
$

716,359

Total assets ...........................................
Long-term debt (5).................................
Other long-term liabilities (6) ................
$
Cash dividends per common share....... $

140,626

—

148,785

—

158,331

—

167,545

—

113,830

—

_________________________
(1) During the third quarter of 2012, we made the decision to prospectively use mark-to-market accounting for our economic hedges. Previously, we reported
all gains (losses) in oil and natural gas revenues and now we reflect gains (losses) on non-designated hedges and the ineffectiveness from cash flow
hedges along with other revenue items in other income (expense) below income from operations. Prior year amounts have been reclassified to conform to
current year presentation.

(2)

(3)

(4)

In June 2012 and December 2012, due to low 12-month average commodity prices, we incurred non-cash ceiling test write-downs of our oil and natural
gas properties of $115.9 million pre-tax ($72.1 million, net of tax) and $167.7 million pre-tax ($104.4 million, net of tax), respectively.

In December 2014, we incurred a non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million, net of tax),
a non-cash write-down associated with the removal of 31 drilling rigs from our fleet along with certain other equipment and drill pipe of $74.3 million
pre-tax ($46.3 million, net of tax), and a non-cash write-down associated with a reduction in the carrying value of three midstream segment systems of
$7.1 million pre-tax ($4.4 million, net of tax).

In total for 2015, we incurred non-cash ceiling test write-downs on our oil and natural gas properties of $1.6 billion pre-tax ($1.0 billion, net of tax). We
also incurred a non-cash write-down on certain drilling rigs and other equipment of approximately $8.3 million pre-tax ($5.1 million, net of tax), and a
non-cash write-down associated with a reduction in the carrying value of three midstream segment systems of $27.0 million pre-tax ($16.8 million, net of
tax).

(5) Long-term debt is net of unamortized discount.

(6)

Includes non-current derivative liabilities.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Please read the following discussion of our financial condition and results of operations in conjunction with the

consolidated financial statements and related notes included in Item 8 of this report.

General

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.

Business Outlook

As discussed in other parts of this report, the success of our business and each of our three main operating segments
depend, on a large part, on the prices we receive for our oil and natural gas production and the demand for oil and natural gas as
well as for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. While our
operations are located within the United States, events outside the United States can also impact us and our industry.

Both within the United States and the world, deteriorating commodity prices have brought about significant changes

affecting our industry and us. The decline in commodity prices has caused us (and other oil and gas companies) to reduce our
level of drilling activity and spending. When drilling activity and spending decline for any sustained period of time the rates for
and the number of our drilling rigs working also tend to decline. In addition, lower commodity prices for any sustained period
of time could impact the liquidity condition of some of our industry partners and customers, which, in turn, might limit their
ability to meet their financial obligations to us.

It is uncertain how long the current depressed prices for oil and natural gas products will continue. As noted elsewhere in

this report, commodity prices are subject to a number of factors most of which are beyond our control.

The impact on our business and financial results as a consequence of the reduction in oil and NGLs (and to a lesser extent

natural gas) prices has had a number of consequences for us, including the following:

•

In December 2015, we determined the value of certain unproved oil and gas properties were diminished (in part or in
whole) based on an impairment evaluation and our anticipated future exploration plans. That determination resulted in
$114.4 million of costs associated with the unproved properties being added to the capitalized costs to be amortized.
For the full year of 2015, we incurred a cumulative non-cash ceiling test write-down of our oil and natural gas
properties of $1.6 billion pre-tax ($1.0 billion net of tax). We expect to incur a non-cash ceiling test write-down in the
first quarter of 2016. It is difficult to predict with reasonable certainty the amount of expected future impairments
given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating
costs, drilling and completion costs, upward or downward reserve revisions, reserve additions, and tax attributes.
Subject to these numerous factors and inherent limitations, holding these factors constant and only adjusting the 12-
month average price to an estimated first quarter ending average (holding February 2016 prices constant for the
remaining one month of 2016), we currently anticipate that we could recognize an impairment in the first quarter of
2016 of approximately $60 million pre-tax. The impact of the significantly higher commodity prices used in the ceiling
test 12-month average price calculation will lessen as those higher prices will roll off from the calculation.

• We have reduced the number of gross wells we plan to drill in 2016 by approximately 57-74% from the number of

gross wells drilled in 2015 due to reduced cash flow from lower commodity prices.

•

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 sold most of these items at auction during 2015.

Several of our drilling rig customers significantly reduced their drilling budgets, resulting in a significant reduction in
the average utilization of our drilling rig fleet. At December 31, 2014, we had 75 drilling rigs operating, during 2015,

we averaged 34.7 drilling rigs operating, and at February 12, 2016, this number was 20. We currently expect further
reductions in 2016.

•

In December 2015, our mid-stream segment incurred a $27.0 million pre-tax write-down of three of its systems 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.

• Due to the low NGLs prices, we are operating our processing facilities in full ethane rejection mode which reduces the
amount of liquids sold. As long as NGLs prices continue to be depressed, we expect to continue operating in full
ethane rejection mode. As low commodity prices continue, we expect the reductions in drilling activity around our
systems will reduce the number of new wells available to connect to our systems and result in lower processed
volumes as production from wells previously connected naturally decline.

• Effective with the October 2015 redetermination, the lenders of our credit agreement decreased our borrowing base
from $725.0 million to $550.0 million. This new amount is above the $500.0 million commitment we have elected
under the credit agreement. While it is anticipated deteriorating commodity prices may result in a further reduction to
our current borrowing base, we believe our liquidity will be adequate to carry out our 2016 capital plans.

We have reduced our total 2016 capital budget by a range of approximately 59-65% as compared to 2015, excluding

acquisitions and ARO liability. Our budget is designed to keep our capital expenditures below our anticipated cash flow and
proceeds from non-core asset sales.

Our 2016 current capital expenditures budget is based on realized prices for the year of $34.57 per barrel of oil, $8.01 per

barrel of NGLs, and $2.24 per Mcf of natural gas. Our budget is subject to possible periodic adjustments for various reasons
including changes in commodity prices and industry conditions. Funding for the budget will come primarily from our cash
flow, non-core asset sales, and, if necessary, borrowings under our credit agreement.

In response to the adverse impacts that the lower commodity prices had on us in 2015 as well as our industry we carried

out the following during 2015 and early 2016:

• We are in the process of consolidating from five to two the number of divisions within our drilling segment allowing

for us to further reduce the costs associated with operating the divisions.

• The higher end of our 2016 capital expenditure budget for exploration and production segment is designed with the

intent to incur the majority of those expenditures in the latter part of the year thus allowing us to take into account
future commodity price movement before we incur those expenditures.

• We have implemented certain reduction in our office and field workforces to account for the reduction in our operating

activities.

• As of February 12, 2016, we have sold approximately $37.4 million of non-core oil and gas properties in 2016 using

the majority of the proceeds to pay down our borrowings under our bank credit agreement.

Executive Summary

Oil and Natural Gas

Fourth quarter 2015 production from our oil and natural gas segment was 4,757,000 barrels of oil equivalent (Boe), a 6%
decrease from the third quarter of 2015 and a 2% decrease from the fourth quarter of 2014. These decreases came mostly from
lower production due to reduced drilling activity and the replacement of reserves as a result of lower oil and NGLs prices. Oil
and NGLs production during the fourth quarter of 2015 was 44% of our total production compared to 47% of our total
production during the fourth quarter of 2014.

Fourth quarter 2015 oil and natural gas revenues decreased 22% from the third quarter of 2015 and decreased 54% from
the fourth quarter of 2014. These deceases were primarily due to lower oil, natural gas, and NGLs prices and to a lesser extent
from reduced production volumes.

Our natural gas and oil prices for the fourth quarter of 2015 decreased 16% and 5%, respectively, compared to the third
quarter of 2015 while our NGLs prices increased 26%. Our NGLs, oil, and natural gas prices decreased 56%, 41%, and 40%,
respectively compared to the fourth quarter of 2014.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) decreased 32% from the third

quarter of 2015 and 64% from the fourth quarter of 2014. The decreases were primarily attributable to decreased oil, natural
gas, and NGLs prices.

Operating cost per Boe produced for the fourth quarter of 2015 decreased 1% from the third quarter of 2015 and
decreased 31% from the fourth quarter of 2014. The decrease from the third quarter of 2015 was primarily due to lower lease
operating expenses (LOE ) partially offset by higher gross production taxes. The decrease from the fourth quarter of 2014 was
primarily due to lower salt water disposal expense, lower LOE, lower gross production tax from lower sales revenue, and lower
general and administrative expenses.

For 2016, we have derivative contracts covering approximately 2,850 Bbls per day of oil production. For the month of
January, we have hedged approximately 90,500 MMBtu per day of natural gas production and for the remainder of 2016, we
have hedged approximately 100,500 MMBtu per day of natural gas production. For 2017, we have hedged approximately 750
Bbls per day of oil production and 25,000 MMBtu per day of natural gas production.

At December 31, 2015, the following non-designated hedges were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price for Swaps

Contracted Market

Jan’16 – Dec’16

Natural gas – swap

35,000 MMBtu/day

$2.625

Natural gas – collar

42,000 MMBtu/day

$2.40 - $2.88

IF – NYMEX (HH)

Jan’16 – Dec'16

Jan’17 – Dec'17

Jan’16 – Jun'16

Jul’16 – Dec'16

Jan’16 – Dec'16

Jul’16 – Dec'16

Jan’17 – Dec'17

Natural gas – three-way collar

13,500 MMBtu/day

$2.70 - $2.20 - $3.26

IF – NYMEX (HH)

Natural gas – three-way collar

15,000 MMBtu/day

$2.50 - $2.00 - $3.32

IF – NYMEX (HH)

Crude oil – collar

2,150 Bbl/day

1,450 Bbl/day

$46.36 - $55.62

$47.50 - $56.40

WTI – NYMEX

Crude oil – three-way collar

700 Bbl/day

$46.50 - $35.00 - $57.00

WTI – NYMEX

Crude oil – three-way collar (1)

700 Bbl/day

$47.50 - $35.00 - $63.50

WTI – NYMEX

Crude oil – three-way collar

750 Bbl/day

$50.00 - $37.50 - $63.90

WTI – NYMEX

_________________________
(1) We pay our counterparty a premium, which can be and is being deferred until settlement.

Subsequent to December 31, 2015, the following non-designated hedges were entered into:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price for Swaps

Contracted Market

Feb’16 – Dec'16

Natural gas – swap

Jan’17 – Dec'17

Natural gas – swap

10,000 MMBtu/day

$2.495

$2.795

IF – NYMEX (HH)

During 2015, we participated in the drilling of 58 wells (34.99 net wells). For 2016, we plan to participate in the drilling

of approximately 15 to 25 gross wells. Our 2016 production guidance is approximately 16.9 to 17.4 MMBoe, a decrease of
13-16% from 2015, actual results will be subject to many factors. This segment’s capital budget for 2016 is a range from $109.0
to $131.0 million, a 52-60% decrease from 2015, excluding acquisitions and ARO liability. As of February 12, 2016, we have
sold approximately $37.4 million of non-core oil and gas properties in 2016.

Contract Drilling

The average number of drilling rigs we operated for 2015 was 34.7 compared to 75.4 in 2014. Late in the fourth quarter
of 2014, the number of our drilling rigs operating started to decline and has continued to decline throughout 2015 due to lower
commodity prices and operators reducing their drilling budgets. As of December 31, 2015, 26 drilling rigs were operating.

Revenue for the fourth quarter of 2015 decreased 22% and 63% from the third quarter of 2015 and fourth quarter of 2014,

respectively. The decreases were primarily due to fewer drilling rigs operating and lower dayrates.

Dayrates for the fourth quarter of 2015 averaged $18,604, a 1% and 9% decrease from the third quarter of 2015 and the
fourth quarter of 2014, respectively. The decreases were primarily due to downward pressure on dayrates with lower demand.

Operating costs for the fourth quarter of 2015 decreased 8% and 58% from the third quarter of 2015 and the fourth

quarter of 2014, respectively. The decreases were due primarily to fewer drilling rigs operating.

Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2015 decreased

39% and 69% from the third quarter of 2015 and the fourth quarter of 2014, respectively. For both comparative periods, we had
fewer drilling rigs operating with lower dayrates.

Operating cost per day for the fourth quarter of 2015 increased 6% and 25% over the third quarter of 2015 and the fourth
quarter of 2014, respectively. The increases were primarily due to less revenue days partially offset by lower direct rig expense
due to fewer drilling rigs operating for both comparative periods.

During 2015, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs. Today,

the drastic reduction in commodity prices for oil and natural gas has changed demand for drilling rigs. All of these factors
ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the
availability of drilling rigs to meet that demand will have an impact on our future dayrates.

As of December 31, 2015, we had nine term drilling contracts with original terms ranging from six months to three years.

Five of these contracts are up for renewal in 2016, (two in the first quarter, two in the third quarter, and one in the fourth
quarter) and four are up for renewal in 2017. Term contracts may contain a fixed rate for the duration of the contract or provide
for rate adjustments within a specific range from the existing rate. Some operators who had signed term contracts have opted to
release the drilling rig and pay an early termination penalty for the remaining term of the contract. During 2015, we recorded
$29.0 million in early termination fees.

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 the first quarter of 2015, we sold one of these drilling rigs to an
unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the drilling rig
resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining drilling rigs
and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar auctions. During
the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds from the sale of
those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million pre-tax. Some of
the equipment that was not sold at the auction will be sold within the next twelve months and remain classified as assets held
for sale. The net book value of those assets is $0.6 million.

We have completed our current new BOSS drilling rig program for 2015. Eight new BOSS drilling rigs have been placed

into service. Some of the long lead time components for three additional BOSS drilling rigs were ordered during 2014 in
anticipation for future demand of the BOSS drilling rigs. With the decline in the drilling market, many of these long lead time
components were either postponed for later delivery or canceled altogether. Currently, we do not have any contracts to build
new BOSS drilling rigs. Our anticipated 2016 capital expenditures for this segment range from $9.0 million to $11.0 million, an
87-89% decrease from 2015.

Mid-Stream

Fourth quarter 2015 liquids sold per day decreased 3% and 18% from the third quarter of 2015 and the fourth quarter of
2014, respectively. The decrease from third quarter of 2015 was due to more effectively operating our processing facilities in
full ethane rejection mode. The decrease from the prior year was due to operating in ethane rejection mode in 2015. For the
fourth quarter of 2015, gas processed per day decreased 8% from the third quarter of 2015 and increased 4% over the fourth
quarter of 2014. The decrease from the third quarter was due to general declines in wells. The increase over prior year was due
to connecting new wells to both existing and newly constructed systems to replace production declines from wells already
connected. For the fourth quarter of 2015, gas gathered per day increased 1% and 10% over the third quarter of 2015 and the
fourth quarter of 2014, respectively. These increases were primarily from well connects throughout 2015.

NGLs prices in the fourth quarter of 2015 were essentially unchanged from the prices received in the third quarter of

2015 and decreased 38% from the prices received in the fourth quarter of 2014. Because certain of the contracts used by our
mid-stream segment for NGLs transactions are commodity-based contracts – under which we receive a share of the proceeds
from the sale of the NGLs – our revenues from those commodity-based contracts fluctuate based on NGLs prices.

Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2015 decreased 10% from

the third quarter of 2015 and decreased 6% from the fourth quarter of 2014. These decreases were primarily due to lower
NGLs, natural gas, and condensate prices reducing revenues. Total operating cost for this segment for the fourth quarter of 2015
decreased 10% and 47% from the third quarter of 2015 and the fourth quarter of 2014, respectively due primarily to the lower
cost of gas purchased.

At our Hemphill Texas system with the completion of the nine-mile pipeline that connects our Buffalo Wallow gathering

system to our Hemphill processing facility, we began transporting Buffalo Wallow gathered gas to our Hemphill facility for
processing. At our Hemphill processing facility, we have three operational processing skids that provide approximately 135
MMcf per day of processing capacity.

In central Oklahoma at our Perkins processing facility, we completed the upgrade of our processing facility which
increased our total processing capacity from 20 MMcf per day to 27 MMcf per day. These improvements consist of processing
plant upgrades along with projects to improve recoveries at this facility. During 2015, we connected 11 new wells to this system
from several producers.

Also in central Oklahoma, at our Minco processing facility, we completed upgrades to this facility which improved our

processing capacity and allowed us to gather and process additional liquid rich gas from third-party producers. With this
upgrade the total processing capacity of this system was increased to approximately 15 MMcf per day.

In the Mississippian play in north central Oklahoma, we completed the upgrade of our Bellmon gathering system along

with the installation of additional compressors. This will allow us to receive additional volume from third-party producers in the
area. We connected 40 new wells to this system from several producers during 2015. At this processing facility we have two
operational processing skids that provide total processing capacity of approximately 90 MMcf per day.

In the Appalachian region, we completed the northern expansion of the Pittsburgh Mills gathering system into Butler

County, Pennsylvania. This project includes a seven-mile trunkline along with a related compressor station. With the
completion of this project we also gain an additional outlet for our gas into NiSource pipeline. The Clinton compressor station
located in Butler County, Pennsylvania was completed and became operational in the fourth quarter of 2015. With the
completion of this expansion project, we now have the ability to connect additional wells that are scheduled to be drilled in this
area in 2016.

Also in the Appalachian area, we completed the construction of our new fee-based gathering system, Snow Shoe
Gathering System, in Centre County, Pennsylvania. This system consists of approximately 12 miles of gathering pipeline. The
pipeline has been installed and is now operational. We began flowing gas on this pipeline in January 2016.

Anticipated 2016 capital expenditures for this segment range from $22.0 million to $24.0 million, a 62-65% decrease

from 2015.

Critical Accounting Policies and Estimates

Summary

In this section, we identify those critical accounting policies we follow in preparing our financial statements and related

disclosures. Many of these policies require us to make difficult, subjective, and complex judgments in the course of making
estimates of matters that are inherently imprecise. Some accounting policies involve judgments and uncertainties to such an
extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions,
or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates
on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from

other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In
the following discussion we will attempt to explain the nature of these estimates, assumptions and judgments, as well as the
likelihood that materially different amounts would be reported in our financial statements under different conditions or using
different assumptions.

The following table lists the critical accounting policies, identifies the estimates and assumptions that can have a

significant impact on the application of these accounting policies, and the financial statement accounts that are affected by these
estimates and assumptions.

Accounting Policies
Full cost method of accounting for oil,
NGLs, and natural gas properties

Estimates or Assumptions
• Oil, NGLs, and natural gas reserves,
estimates, and related present value
of future net revenues

• Valuation of unproved properties
• Estimates of future development

costs

Accounts Affected

• Oil and natural gas properties
• Accumulated depletion, depreciation

and amortization

• Provision for depletion, depreciation

and amortization

• Impairment of oil and natural gas

properties

• Long-term debt and interest expense

Accounting for ARO for oil, NGLs, and
natural gas properties

• Cost estimates related to the

plugging and abandonment of wells

• Oil and natural gas properties
• Accumulated depletion, depreciation

• Timing of cost incurred

and amortization

Accounting for impairment of long-
lived assets

• Forecast of undiscounted estimated
future net operating cash flows

• Provision for depletion, depreciation

and amortization

• Current and non-current liabilities
• Operating expense

• Drilling and mid-stream property

and equipment

• Accumulated depletion, depreciation

and amortization

• Provision for depletion, depreciation

and amortization

• Other intangible assets

Goodwill

• Forecast of discounted estimated
future net operating cash flows

• Terminal value
• Weighted average cost of capital

• Goodwill

Accounting for value of stock
compensation awards

• Estimates of stock volatility
• Estimates of expected life of awards
granted
• Estimates of rates of forfeitures

• Oil and natural gas properties
• Shareholder’s equity
• Operating expenses
• General and administrative expenses

Accounting for derivative instruments
and hedging

• Hedges measured for effectiveness

• Current and non-current derivative

and ineffectiveness (2013)
• Non-qualifying and qualifying

derivatives measured at fair value

assets and liabilities

• Other comprehensive income as a

component of equity (2013)

• Oil and natural gas revenue (2013)
• Gain (loss) on derivatives not

designated as hedges and hedge
ineffectiveness, net

Significant Estimates and Assumptions

Full Cost Method of Accounting for Oil, NGLs, and Natural Gas Properties. The determination of our oil, NGLs, and

natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs, and natural gas that
cannot be measured in an exact manner. The degree of accuracy of these estimates depends on a number of factors, including,
the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual
judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. The
audit of our reserve wells or locations as of December 31, 2015 covered those that we projected to comprise 79% of the total
proved developed discounted future net income and 81% of the total proved discounted future net income based on the

unescalated pricing policy of the SEC. Included in Part I, Item 1 of this report are the qualifications of our independent
petroleum engineering firm and our employees responsible for the preparation of our reserve reports.

As a general rule, the accuracy of estimating oil, NGLs, and natural gas reserves varies with the reserve classification and

the related accumulation of available data, as shown in the following table:

Type of Reserves

Nature of Available Data

Degree of Accuracy

Proved undeveloped

Data from offsetting wells, seismic data

Less accurate

Proved developed non-producing The above as well as logs, core samples, well tests, pressure data More accurate

Proved developed producing

The above as well as production history, pressure data over time Most accurate

Assumptions of future oil, NGLs, and natural gas prices and operating and capital costs also play a significant role in

estimating these reserves as well as the estimated present value of the cash flows to be received from the future production of
those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to the economic limit (that
point when the projected costs and expenses of producing recoverable oil, NGLs, and natural gas reserves is greater than the
projected revenues from the oil, NGLs, and natural gas reserves). But more significantly, the estimated present value of the
future cash flows from our oil, NGLs, and natural gas reserves is sensitive to prices and costs, and may vary materially based on
different assumptions. Companies, like ours, using full cost accounting 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.

We compute DD&A on a units-of-production method. Each quarter, we use the following formulas to compute the

provision for DD&A for our producing properties:

• DD&A Rate = Unamortized Cost / End of Period Reserves Adjusted for Current Period Production

•

Provision for DD&A = DD&A Rate x Current Period Production

Oil, NGLs, and natural gas reserve estimates have a significant impact on our DD&A rate. If future reserve estimates for a

property or group of properties are revised downward, the DD&A rate will increase as a result of the revision. Alternatively, if
reserve estimates are revised upward, the DD&A rate will decrease. Based on our 2015 production level of 20.0 MMBoe, a
decrease in the amount of our 2015 oil, NGLs, and natural gas reserves by 5% would increase our DD&A rate by $0.48 per Boe
and would decrease pre-tax income by $9.6 million annually. Conversely, an increase in our 2015 oil, NGLs, and natural gas
reserves by 5% would decrease our DD&A rate by $0.48 per Boe and would increase pre-tax income by $9.6 million annually.

The DD&A expense on our oil and natural gas properties is calculated each quarter using period end reserve quantities

adjusted for current period production.

We account for our oil and natural gas exploration and development activities using the full cost method of accounting.

Under this method, we capitalize all costs incurred in the acquisition, exploration, and development of oil and natural gas
properties. At the end of each quarter, the net capitalized costs of our oil and natural gas properties are limited to that amount
which is the lower of unamortized costs or a ceiling. The ceiling is defined as the sum of the present value (using a 10%
discount rate) of the estimated future net revenues from our proved reserves (based on the unescalated 12-month average price
on our oil, NGLs, and natural gas adjusted for any cash flow hedges), plus the cost of properties not being amortized, plus the
lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income taxes.
If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are required to write-down the excess
amount. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders’
equity in the period of occurrence and results in lower DD&A expense in future periods. Once incurred, a write-down cannot be
reversed.

The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when the

prices for oil, NGLs, and natural gas are depressed or if we have large downward revisions in our estimated proved oil, NGLs,
and natural gas reserves. Application of these rules during periods of relatively low prices, even if temporary, increases the

chance of a ceiling test write-down. At December 31, 2015, our reserves were calculated based on applying 12-month 2015
average unescalated prices of $50.28 per barrel of oil, $19.47 per barrel of NGLs, and $2.59 per Mcf of natural gas (then
adjusted for price differentials) over the estimated life of each of our oil and natural gas properties. In total for 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)
due to the inclusion of the impaired value of certain unproved properties and a reduction of the 12-month average commodity
prices during the year.

We expect to incur a non-cash ceiling test write-down in the first quarter of 2016. It is difficult to predict with reasonable
certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but
not limited to, future pricing, operating costs, drilling and completion costs, upward or downward reserve revisions, reserve
additions, and tax attributes. Subject to these numerous factors and inherent limitations, holding these factors constant and only
adjusting the 12-month average price to an estimated first quarter ending average (holding February 2016 prices constant for
the remaining one month of 2016), we currently anticipate that we could recognize an impairment in the first quarter of 2016 of
approximately $60 million pre-tax. The estimated first quarter 2016 impairment is partially the result of a decrease in our
proved undeveloped reserves of approximately 26%. These anticipated decreases are primarily due to certain locations no
longer being economical under the adjusted 12-month average price for the first quarter. Based on this estimated 12-month
average price, we would eliminate those locations from our future development plan. The impact of the significantly higher
commodity prices used in the ceiling test 12-month average price calculation will lessen as those higher prices will roll off from
the calculation. Given the uncertainty associated with the factors used in calculating our estimate of both our future period
ceiling test write-down and the decrease in our undeveloped reserves, these estimates should not necessarily be construed as
indicative of our future development plans or financial results.

Derivative instruments qualifying as cash flow hedges are included in the computation of limitation on capitalized costs.

All of our cash flow hedges expired as of December 31, 2013 and no longer effect this computation. Our oil and natural gas
derivatives are discussed in Note 12 of the Notes to our Consolidated Financial Statements.

We use the sales method for recording natural gas sales. This method allows for the recognition of revenue, which may be

more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease
operating costs from all wells as incurred. The expenses relating to the wells in which we have a production imbalance are not
material.

Costs Withheld from Amortization. Costs associated with unproved properties are excluded from our amortization base

until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and related seismic data, wells
currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either
transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible
impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has
occurred.

Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base

involve a significant amount of judgment and may be subject to changes over time based on several factors, including our
drilling plans, availability of capital, project economics and results of drilling on adjacent acreage. In December 2014 and
December 2015, we determined the value of certain unproved oil and gas properties were diminished (in part or in whole) based
on an impairment evaluation and our anticipated future exploration plans. That determination resulted in $73.7 million in 2014
and $114.4 million in 2015 of costs associated with the unproved properties being added to the capitalized costs to be
amortized. At December 31, 2015, we had a total of approximately $337.1 million of costs excluded from the amortization
base of our full cost pool.

Accounting for ARO for Oil, NGLs, and Natural Gas Properties. We record the fair value of liabilities associated with the

retirement of assets having a long life. In our case, when the reserves in each of our oil or gas wells deplete or otherwise
become uneconomical, we are required to incur costs to plug and abandon the wells. These costs are recorded in the period in
which the liability is incurred (at the time the wells are drilled or acquired). We do not have any assets restricted for the purpose
of settling these ARO liabilities. Our engineering staff uses historical experience to determine the estimated plugging costs
taking into account the type of well (either oil or natural gas), the depth of the well and physical location of the well to
determine the estimated plugging costs.

Accounting for Impairment of Long-Lived Assets. Drilling equipment, transportation equipment, gas gathering and

processing systems, and other property and equipment are carried at cost less accumulated depreciation. Renewals and

enhancements are capitalized while repairs and maintenance are expensed. We review the carrying amounts of long-lived assets
for potential impairment annually, typically during the fourth quarter, or when events occur or changes in circumstances suggest
that these carrying amounts may not be recoverable. Changes that could prompt such an assessment may include equipment
obsolescence, changes in the market demand for a specific asset, changes in commodity prices, periods of relatively low drilling
rig utilization, declining revenue per day, declining cash margin per day, or overall changes in general market conditions. Assets
are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the
asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the
loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The 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 and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve
expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding
future industry conditions and their effect on future utilization levels, dayrates, and costs. The use of different estimates and
assumptions could result in materially different carrying values of our assets.

As of December 31, 2015, with continuing declines to commodity prices and an outlook that commodity prices may be

lower for longer, we lowered our expectations about future utilization of our drilling rigs and associated cash flows. We
performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract
drilling segment. With respect to these assets, future cash flows were estimated over the expected remaining life of the assets.
Management determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived
assets within our contract drilling segment by 99%, and there was no impairment at December 31, 2015.

In 2014, our mid-stream segment incurred 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. No significant
impairment was recorded at December 31, 2013.

Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired.
Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has
decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment
testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and
accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment,
utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated
discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No
goodwill impairment was recorded at December 31, 2015, 2014, or 2013. Based on our impairment test performed as of
December 31, 2015, the fair value of our drilling segment exceeded its carrying value by 19%. A period of sustained reduced
commodity prices resulting in further reductions in the number of our drilling rigs working and the rates we charge for them
could result in a non-cash goodwill impairment in future periods.

Turnkey and Footage Drilling Contracts. Because our contract drilling operations do not bear the risk of completion of a
well being drilled under a “daywork” contract, we recognize revenues and expense generated under “daywork” contracts as the
services are performed. Under “footage” and “turnkey” contracts we bear the risk of completion of the well, so revenues and
expenses are recognized when the well is substantially completed. Substantial completion is determined when the well bore
reaches the depth specified in the contract. The entire amount of a loss, if any, is recorded when the loss can be reasonably
determined, however, any profit is recorded only at the time the well is finished. The costs of drilling contracts uncompleted at
the end of the reporting period (which includes expenses incurred to date on “footage” or “turnkey” contracts) are included in
other current assets. We did not drill any wells under turnkey or footage contracts in 2015, 2014, or 2013.

Accounting for Value of Stock Compensation Awards. To account for stock-based compensation, compensation cost is
measured at the grant date based on the fair value of an award and is recognized over the service period, which is usually the
vesting period. We elected to use the modified prospective method, which requires compensation expense to be recorded for all
unvested stock options and other equity-based compensation beginning in the first quarter of adoption. The determination of the
fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate
option pricing model, the expected life of the award and performance vesting criteria assumptions. As there are inherent
uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the
recorded stock compensation may not accurately reflect the amount ultimately earned by the employee.

Accounting for Derivative Instruments and Hedging. For our economic hedges that we did not apply cash flow

accounting to, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported
in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net in our Consolidated Statements of
Operations. The commodity derivative instruments we had under cash flow accounting expired as of December 2013. Previous
changes in the fair value of derivatives designated as cash flow hedges, to the extent they were effective in offsetting cash flows
attributable to the hedged risk, were recorded in OCI until the hedged item was recognized into earnings. When the hedged item
was recognized into earnings, it was reported in oil and natural gas revenues. Any change in fair value resulting from
ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net.

New Accounting Standards

Income Taxes: Balance Sheet Classification of Deferred Taxes. The FASB has issued ASU 2015-17. This changes how
deferred taxes are classified on organizations' balance sheets. Organizations will be required to classify all deferred tax assets
and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. For public
companies, the amendments are effective for financial statements issued for annual periods beginning after December 15, 2016,
and interim periods within those annual periods. Early adoption of the amendments is permitted. We are in the process of
evaluating the impact it will have on our financial statements.

Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The FASB has issued ASU
2015-03. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the
balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The FASB has
also issued ASU 2015-15. The amendments in this ASU allow an entity to defer and present debt issuance cost as an asset and
subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of
whether there are any outstanding borrowings on the line-of-credit arrangement. For public business entities, the amendments
are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within
those fiscal years. Early adoption of the amendments is permitted for financial statements that have not been previously issued.
The amendments should be applied on a retrospective basis, wherein the balance sheet of each individual period presented
should be adjusted to reflect the period-specific effects of applying the new guidance. We do not expect the adoption of this
guidance will have a material impact on our financial statements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP

that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of
nonfinancial assets unless those contracts are within the scope of other standards (e.g., insurance contracts or lease contracts).
The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or
services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for
those goods or services. The FASB has issued 2015-14, which defers the effective date to annual reporting periods beginning
after December 15, 2017, including interim reporting periods within that reporting period. We are in the process of evaluating
the impact it will have on our financial statements.

Financial Condition and Liquidity

Summary.

Our financial condition and liquidity primarily depends on the cash flow from our operations and borrowings under our

credit agreement. The principal factors determining the amount of our cash flow are:

•

the quantity of natural gas, oil, and NGLs we produce;

the prices we receive for our natural gas, oil, and NGLs production;

•

the demand for and the dayrates we receive for our drilling rigs; and

the fees and margins we obtain from our natural gas gathering and processing contracts.

We currently believe we have sufficient cash flow and liquidity to meet our obligations and remain in compliance with
our debt covenants for the next twelve months. Our ability to meet our debt covenants (under our credit agreement as well as
our Indenture) and our capacity to incur additional indebtedness will depend on our future performance, which in turn will be
affected by financial, business, economic, regulatory, and other factors. For example, lower oil, natural gas, and NGLs prices
since the last redetermination could result in a redetermination of the borrowing base under our credit agreement to a lower
level and therefore reduce or limit our ability to incur indebtedness. As a result, we monitor our liquidity and capital resources,
endeavor to anticipate potential covenant compliance issues and work with the lenders under our credit agreement to address
those issues, if any, ahead of time.

As part of our plan to manage liquidity risks, we have lowered our capital expenditures budget, focused our drilling
program on our highest return plays, and continue to explore opportunities to divest non-core assets and properties. As of
February 12, 2016, we have sold approximately $37.4 million of non-core oil and gas properties in 2016 using the majority of
the proceeds to pay down our borrowings under our bank credit agreement. If necessary, we could sell other non-core assets and
use the proceeds to further reduce our outstanding borrowings.

The following is a summary of certain financial information for the years ended December 31:

Net cash provided by operating activities......................................................

Net cash used in investing activities ..............................................................

Net cash provided by (used in) financing activities.......................................

Net increase (decrease) in cash and cash equivalents ............................... $

Cash flows from Operating Activities

2015

446,944
(549,778)
102,620

2014
(In thousands)
708,993
$
(920,597)
194,060
(17,544) $

(214) $

2013

674,331
(579,180)
(77,532)
17,619

Our operating cash flow is primarily influenced by the prices we receive for our oil, NGLs, and natural gas production,
the quantity of oil, NGL, and natural gas we produce, settlements of derivative contracts, third-party demand for our drilling
rigs and mid-stream services, and the rates we are able to charge for those services. Our cash flows from operating activities are
also impacted by changes in working capital.

Net cash provided by operating activities during 2015 decreased by $262.0 million from 2014 due primarily to lower
revenues due to lower commodity prices and lower drilling rig utilization partially offset by $29.0 million we recorded in early
termination fees and by changes in operating assets and liabilities related to the timing of cash receipts and disbursements.

Cash flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the
exploration for and production of oil, NGLs, and natural gas. These capital expenditures are necessary to offset inherent
declines in production, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities decreased by $370.8 million in 2015 compared to 2014. The change was due
primarily to a decrease in capital expenditures partially offset by the proceeds received from the disposition of assets. See
additional information on capital expenditures below under Capital Requirements.

Cash Flows from Financing Activities

Cash flows provided by financing activities decreased by $91.4 million in 2015 compared to 2014. This decrease was
primarily due to our borrowings under our credit agreement as well as a decrease in our book overdrafts (which are checks that
have been issued but not presented to our bank for payment before the end of the period).

At December 31, 2015, we had unrestricted cash totaling $0.8 million and had borrowed $281.0 million of the $500.0

million we currently have available under our credit agreement. Our credit agreement is used primarily for working capital and
capital expenditures.

The following is a summary of certain financial information as of December 31, and for the years ended December 31:

Working capital...................................................................................... $
Long-term debt (1) ..................................................................................
$
Shareholders’ equity...............................................................................

Net income (loss) ...................................................................................

_________________________
(1) Long-term debt is net of unamortized discount.

2015

2014
(In thousands except percentages)
$

(10,633)
927,662

$
1,313,580 (2) $
(1,037,361) (2) $

(51,680)
812,163

$
2,332,394 (2) $
136,276 (2) $

2013

(31,542)
645,696

2,173,392

184,746

(2)

In 2015 and 2014, we incurred non-cash ceiling test write-downs of our oil and natural gas properties of $1.6 billion and $76.7 million pre-tax ($1.0
billion and $47.7 million, net of tax), respectively. In December 2014, we incurred a non-cash write-down associated with the removal of 31 drilling rigs
from our fleet along with certain other equipment and drill pipe of $74.3 million pre-tax ($46.3 million net of tax) and then an additional non-cash write-
down in 2015 of $8.3 million pre-tax ($5.1 million, net of tax). Also in December 2014, we incurred a non-cash write-down associated with a reduction
in the carrying value of three midstream segment systems of $7.1 million pre-tax ($4.4 million net of tax). Then in December 2015, we incurred a non-
cash write-down associated with the reduction in the carrying value of three midstream segment gathering systems of $27.0 million pre-tax ($16.8 million,
net of tax). The write-downs impacted our shareholders’ equity, ratio of long-term debt to total capitalization, and net income (loss) for years 2015 and
2014. There was no impact on our compliance with the covenants contained in our credit agreement.

Working Capital

Typically, our working capital balance fluctuates, in part, because of the timing of our trade accounts receivable and
accounts payable and the fluctuation in current assets and liabilities associated with the mark to market value of our derivative
activity. We had negative working capital of $10.6 million, $51.7 million, and $31.5 million as of December 31, 2015, 2014,
and 2013, respectively. This is primarily from the timing of our accounts payable associated with our capital expenditures
partially offset by lower accounts receivable due to lower revenues. Our credit agreement is used primarily for working capital
and capital expenditures. At December 31, 2015, we had borrowed $281.0 million of the $500.0 million currently available to
us under our credit agreement. The effect of our derivatives increased working capital by $10.2 million and $31.1 million as of
December 31, 2015 and 2014, respectively, and decreased working capital by $5.0 million as of December 31, 2013.

The following table summarizes certain operating information for the years ended December 31:

Oil and Natural Gas:
Oil production (MBbls)..................................................................................

Natural gas liquids production (MBbls) ........................................................

Natural gas production (MMcf) .....................................................................
Average oil price per barrel received............................................................. $
Average oil price per barrel received excluding derivatives.......................... $
Average NGLs price per barrel received........................................................ $
Average NGLs price per barrel received excluding derivatives.................... $
Average natural gas price per mcf received................................................... $
Average natural gas price per mcf received excluding derivatives................ $
Contract Drilling:

Average number of our drilling rigs in use during the period........................

Total number of drilling rigs available for use at the end of the period.........
Average dayrate ............................................................................................. $
Mid-Stream:
Gas gathered—Mcf/day .................................................................................

Gas processed—Mcf/day ...............................................................................

Gas liquids sold—gallons/day .......................................................................

Number of natural gas gathering systems......................................................

Number of processing plants .........................................................................

2015

2014

2013

3,783

5,274

65,546

50.79

45.04

10.12

2.63

2.25

34.7

3,844

4,628

58,854

89.43

89.32

30.95

3.92

4.03

75.4

3,360

3,914

56,757

95.06

95.18

31.79

3.32

3.33

65.0

121

19,455

20,043

19,646

353,771

182,684

577,513

319,348

161,282

733,406

309,554

140,584

543,602

_________________________
(1)

In 2015, our mid-stream segment transferred 11 natural gas gathering systems to our oil and natural gas segment.

Oil and Natural Gas Operations

Any significant change in oil, NGLs, or natural gas prices has a material effect on our revenues, cash flow, and the value

of our oil, NGLs, and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather
conditions, supply imbalances, and by worldwide oil price levels. Domestic oil prices are primarily influenced by world oil
market developments. All of these factors are beyond our control and we cannot predict nor measure their future influence on
the prices we will receive.

Based on our 2015 production, a $0.10 per Mcf change in what we are paid for our natural gas production, without the

effect of derivatives, would result in a corresponding $520,000 per month ($6.2 million annualized) change in our pre-tax
operating cash flow. Our 2015 average natural gas price was $2.63 compared to an average natural gas price of $3.92 for 2014
and $3.32 for 2013. A $1.00 per barrel change in our oil price, without the effect of derivatives, would have a $303,000 per
month ($3.6 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices,
without the effect of derivatives, would have a $419,000 per month ($5.0 million annualized) change in our pre-tax operating
cash flow based on our production in 2015. Our 2015 average oil price per barrel was $50.79 compared with an average oil
price of $89.43 in 2014 and $95.06 in 2013, and our 2015 average NGLs price per barrel was $10.12 compared with an average
NGLs price of $30.95 in 2014 and $31.79 in 2013.

Because commodity prices have an effect on the value of our oil, NGLs, and natural gas reserves, declines in those prices

can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the
semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is
based mainly on the value of our oil, NGLs, and natural gas reserves. A reduction could limit our ability to carry out our
planned capital projects. We expect to incur a non-cash ceiling test write-down in the first quarter of 2016. It is difficult to
predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test
calculation including, but not limited to, future pricing, operating costs, drilling and completion costs, upward or downward
reserve revisions, reserve additions, and tax attributes. Subject to these numerous factors and inherent limitations, holding these

factors constant and only adjusting the 12-month average price to an estimated first quarter ending average (holding February
2016 prices constant for the remaining one month of 2016), we currently anticipate that we could recognize an impairment in
the first quarter of 2016 of approximately $60 million pre-tax. The impact of the significantly higher commodity prices used in
the ceiling test 12-month average price calculation will lessen as those higher prices will roll off from the calculation.

Our natural gas production is sold to intrastate and interstate pipelines, to independent marketing firms and gatherers
under contracts with terms generally ranging anywhere from one month to five years. Our oil production is sold to independent
marketing firms generally under six month contracts.

Contract Drilling Operations

Many factors influence the number of drilling rigs we are working at any given time as well as the costs and revenues

associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other
drilling contractors, the prevailing prices for oil, NGLs, and natural gas, availability and cost of labor to run our drilling rigs,
and our ability to supply the equipment needed.

Although our drilling rig personnel are a key component to the overall success of our drilling services, with the present
conditions existing in the drilling industry, we do not anticipate increases in the compensation paid to those personnel in the near
term.

During 2015, almost all of our working drilling rigs were drilling horizontal or directional wells for oil and NGLs.
Today, the drastic reduction in commodity prices for oil and natural gas has changed demand for drilling rigs. All of these
factors ultimately affect the demand and mix of the type of drilling rigs used by our customers. The future demand for and the
availability of drilling rigs to meet that demand will have an impact on our future dayrates. For 2015, our average dayrate was
$19,455 per day compared to $20,043 and $19,646 per day for 2014 and 2013, respectively. Our average number of drilling rigs
used in 2015 was 34.7 (38%) compared with 75.4 (63%) and 65.0 (52%) in 2014 and 2013, respectively. Based on the average
utilization of our drilling rigs during 2015, a $100 per day change in dayrates has a $3,470 per day ($1.3 million annualized)
change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and production segment. Some of the drilling

services we perform on our properties are, depending on the timing of those services, deemed to be associated with the
acquisition of an ownership interest in the property. In those cases, revenues and expenses for those services are eliminated in
our statement of operations, with any profit recognized as a reduction in our investment in our oil and natural gas properties.
The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third
parties. We eliminated revenue of $22.1 million, $89.5 million, and $64.3 million for 2015, 2014, and 2013, respectively, from
our contract drilling segment and eliminated the associated operating expense of $18.3 million, $62.4 million, and $46.9 million
during 2015, 2014, and 2013, respectively, yielding $3.8 million, $27.1 million, and $17.4 million during 2015, 2014, and 2013,
respectively, as a reduction to the carrying value of our oil and natural gas properties.

In December 2014, we removed from service 31 drilling rigs, some older top drives, and certain drill pipe no longer

Mid-Stream Operations

This segment is engaged primarily in the buying, selling, gathering, processing, and treating of natural gas. It operates
three natural gas treatment plants, 13 processing plants, 25 gathering systems, and approximately 1,464 miles of pipeline. Its
operations are located in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia. This segment enhances our ability to
gather and market not only our own natural gas and NGLs but also that owned by third parties and serves as a mechanism
through which we can construct or acquire existing natural gas gathering and processing facilities. During 2015, 2014, and 2013
this segment purchased $57.6 million, $80.9 million, and $83.0 million, respectively, of our oil and natural gas segment's

natural gas and NGLs production, and provided gathering and transportation services of $7.6 million, $8.7 million, and $8.0
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.

Our mid-stream segment gathered an average of 353,771 Mcf per day in 2015 compared to 319,348 Mcf per day in 2014
and 309,554 Mcf per day in 2013. It processed an average of 182,684 Mcf per day in 2015 compared to 161,282 Mcf per day in
2014 and 140,584 Mcf per day in 2013, and sold NGLs of 577,513 gallons per day in 2015 compared to 733,406 gallons per
day in 2014 and 543,602 gallons per day in 2013. Gas gathering volumes per day in 2015 increased primarily from new wells
connected to our systems between the comparative periods. Volumes processed increased primarily due to new wells connected.
NGLs sold decreased primarily from being in ethane rejection mode.

Our Credit Agreement and Senior Subordinated Notes

Credit Agreement. On April 10, 2015, we amended our Senior Credit Agreement (credit agreement) to extend the maturity

date from September 13, 2016 to April 10, 2020.The amount we can borrow is the lesser of the amount we elect (from time to
time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to
exceed the maximum credit agreement amount of $900.0 million. Our current commitment amount is $500.0 million. Our
current borrowing base is $550.0 million. We are charged a commitment fee ranging from 0.375% to 0.50% on the amount
available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing
base. To date, for this new amendment, we paid $2.6 million in origination, agency, syndication, and other related fees. We are
amortizing these fees over the life of the credit agreement.

The current lenders under our credit agreement and their respective participation interests are as follows:

Lender
BOK (BOKF, NA, dba Bank of Oklahoma).......................................................................................................
Compass Bank ....................................................................................................................................................
BMO Harris Financing, Inc. ...............................................................................................................................
Bank of America, N.A. .......................................................................................................................................
Comerica Bank ...................................................................................................................................................
Wells Fargo Bank, N.A.......................................................................................................................................
Canadian Imperial Bank of Commerce ..............................................................................................................
Toronto Dominion (New York), LLC.................................................................................................................
The Bank of Nova Scotia....................................................................................................................................

Participation
Interest

17 %

15 %

8 %

4 %
100%

The amount of the borrowing base–which is subject to redetermination by the lenders on April 1st and October 1st of

each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. Effective with
the October 2015 redetermination, the lenders under our credit agreement decreased our borrowing base from $725.0 million to
$550.0 million. We or the lenders may request a onetime special redetermination of the borrowing base between each scheduled
redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the
requirements set forth in the credit agreement. While it is anticipated deteriorating commodity prices may result in a reduction
to our current borrowing base, we believe our liquidity will be adequate to carry out our 2016 capital plans.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered

Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50%
depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days,
whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that in any
event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in
whole or in part at anytime, without a premium or penalty. At December 31, 2015 and February 12, 2016, we had $281.0
million and $262.9 million, respectively, outstanding borrowings under our credit agreement.

We can use borrowings for financing general working capital requirements for (a) exploration, development, production
and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of
credit, (d) contract drilling services, and (e) general corporate purposes.

The credit agreement prohibits, among other things:

•

the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net
income for the preceding fiscal year;

the incurrence of additional debt with certain limited exceptions; and

the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except in favor of our lenders.

The credit agreement also requires that we have at the end of each quarter:

•

a current ratio (as defined in the credit agreement) of not less than 1 to 1; and

a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently
ended rolling four fiscal quarters of no greater than 4 to 1.

As of December 31, 2015, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior

subordinated notes (the Notes). Interest on the Notes is payable semi-annually (in arrears) on May 15 and November 15 of each
year. The Notes will mature on May 15, 2021. In connection with the issuance of the Notes, we incurred $14.7 million of fees
that are being amortized as debt issuance cost over the life of the Notes.

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association

(successor to Wilmington Trust FSB), as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of
May 18, 2011, between us, the Guarantors, and the Trustee, and as further supplemented by the Second Supplemental Indenture
dated as of January 7, 2013, between us, the Guarantors and the Trustee (as supplemented, the 2011 Indenture), establishing the
terms and providing for the issuance of the Notes. The Guarantors are all of our direct and indirect subsidiaries. The discussion
of the Notes in this report is qualified by and subject to the actual terms of the 2011 Indenture.

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes

(registered under registration statements) are full and unconditional, joint and several, subject to certain automatic customary
releases, are subject to certain restrictions on the sale, disposition, or transfer of the capital stock or substantially all of the
assets of a subsidiary guarantor, and other conditions and terms set out in the Indenture. Any of our subsidiaries that are not
Guarantors are minor. There are no significant restrictions on our ability to receive funds from our subsidiaries through
dividends, loans, advances or otherwise.

At any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of

the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. On and
after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and
unpaid interest. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all
or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued
and unpaid interest, if any, to the date of purchase. The 2011 Indenture contains customary events of default. The 2011
Indenture also contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur
or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness;
transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with
other companies. We were in compliance with all covenants of the Notes as of December 31, 2015.

Capital Requirements

Oil and Natural Gas Dispositions, Acquisitions, and Capital Expenditures. Most of our capital expenditures for this
segment are discretionary and directed toward future growth. Any decision to increase our oil, NGLs, and natural gas reserves
through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on
investment, future drilling potential, and opportunities to obtain financing under the circumstances involved, all of which

provide us with a large degree of flexibility in deciding when and if to incur these costs. We completed drilling 58 gross wells
(34.99 net wells) in 2015 compared to 186 gross wells (121.00 net wells) in 2014, and 149 gross wells (91.14 net wells) in
2013. Our 2015 total capital expenditures for our oil and natural gas segment, excluding a $5.7 million reduction in the ARO
liability and $0.2 million in acquisitions, totaled $273.5 million compared to 2014 capital expenditures of $772.2 million
(excluding a $37.7 million reduction in the ARO liability and $5.7 million in acquisitions), and 2013 capital expenditures of
$549.2 million (excluding an $18.0 million reduction in the ARO liability).

For all of 2016, we plan to participate in drilling approximately 15 to 25 gross wells and estimate our total capital
expenditures (excluding any possible acquisitions) for our oil and natural gas segment will be a range of approximately $109.0
million to $131.0 million. Whether we are able to drill all of those wells is dependent on a number of factors, many of which
are beyond our control and include the availability of drilling rigs, availability of pressure pumping services, prices for oil,
NGLs, and natural gas, demand for oil, NGLs, and natural gas, the cost to drill wells, the weather, and the efforts of outside
industry partners.

In August 2013, we sold some Bakken property interests. The proceeds, net of related expenses, were $57.1 million. In
addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million for 2013. Proceeds from
these dispositions reduced the net book value of the full cost pool with no gain or loss recognized. We sold non-core oil and
natural gas assets, net of related expenses, for $1.9 million and $33.1 million during 2015 and 2014, respectively. Proceeds
from those dispositions reduced the net book value of our full cost pool with no gain or loss recognized. As of February 12,
2016, we have sold approximately $37.4 million of non-core oil and gas properties in 2016 using the majority of the proceeds to
pay down our borrowings under our bank credit agreement.

Contract Drilling Dispositions, Acquisitions, and Capital Expenditures. During 2013, we sold four of our 2,000
horsepower electric drilling rigs and one 3,000 horsepower electric drilling rigs. All of these sales were to unaffiliated third-
parties.

During the first quarter of 2014. we sold four additional 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

During the first half of 2015, five BOSS drilling rigs were constructed and placed into service for third-party operators.
The long lead time components for three additional BOSS drilling rigs were ordered in 2014 in anticipation for future demand
of the BOSS drilling rigs. However, with the decline in the drilling market, many of these long lead time components were
either postponed for later delivery or canceled altogether. Currently, we do not have any contracts to build new BOSS drilling
rigs.

Our anticipated 2016 capital expenditures for this segment range from $9.0 million to $11.0 million. We have spent $84.8

million for capital expenditures during 2015 compared to $176.7 million in 2014, and $64.3 million in 2013.

Mid-Stream Dispositions, Acquisitions, and Capital Expenditures. At our Hemphill Texas system with the completion of

the nine-mile pipeline that connects our Buffalo Wallow gathering system to our Hemphill processing facility, we began
transporting Buffalo Wallow gathered gas to our Hemphill facility for processing. At our Hemphill processing facility, we have
three operational processing skids that provide approximately 135 MMcf per day of processing capacity.

In central Oklahoma at our Perkins processing facility, we completed the upgrade of our processing facility which
increased our total processing capacity from 20 MMcf per day to 27 MMcf per day. These improvements consist of processing
plant upgrades along with projects to improve recoveries at this facility. During 2015, we connected 11 new wells to this system
from several producers.

Also in central Oklahoma, at our Minco processing facility, we completed upgrades to this facility which improved our

In the Mississippian play in north central Oklahoma, we completed the upgrade of our Bellmon gathering system along

In the Appalachian region, we completed the northern expansion of the Pittsburgh Mills gathering system into Butler

During 2015, our mid-stream segment incurred $63.5 million in capital expenditures as compared to $51.1 million,

excluding $28.2 million for capital leases, in 2014, and $96.1 million in 2013. For 2016, our estimated capital expenditures
range from $22.0 million to $24.0 million.

Contractual Commitments

At December 31, 2015, we had the following contractual obligations:

Long-term debt (1).................................................
Operating leases (2) ...............................................
Capital lease interest and maintenance (3).............
Drill pipe, drilling components, and equipment
purchases (4) ......................................................

Enterprise Resource Planning software

obligations (5) ....................................................

1,911
Total contractual obligations ................................ $ 1,222,320

Payments Due by Period

Total

Less Than
1 Year

$ 1,193,206

50,304

2-3
Years
(In thousands)
100,609
$

4-5
Years

After
5 Years

376,366

665,927

8,311

12,143

6,749

6,407

2,619

6,699

1,425

1,740

4,799

—

486

164

4,173

—

552

—

67,454

107,634

380,753

666,479

_________________________
(1) See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit
agreement and includes interest calculated using our December 31, 2015 interest rates of 6.625% for the Notes and 2.6% for the credit agreement.

(2) We lease office space or yards in Edmond, Oklahoma City, and Tulsa, Oklahoma; Houston, Texas; Englewood, Colorado; Pinedale, Wyoming; and

Pittsburgh, Pennsylvania under the terms of operating leases expiring through December 2021. Additionally, we have several equipment leases and lease
space on short-term commitments to stack excess drilling rig equipment and production inventory.

(3) Maintenance and interest payments are included in our capital lease agreements. The capital leases are discounted using annual rates of 4.0%. Total

maintenance and interest remaining are $9.4 million and $2.7 million, respectively.

(4) We have committed to purchase approximately $6.7 million of new drilling rig components, drill pipe, and related equipment over the next twelve

months.

(5) We have committed to pay $1.4 million for Enterprise Resource Planning software and $0.5 million for maintenance for one year following

implementation.

At December 31, 2015, we also had the following commitments and contingencies that could create, increase or

accelerate our liabilities:

Estimated Amount of Commitment Expiration Per Period

Other Commitments

Total
Accrued

Deferred compensation plan (1) .............................
Separation benefit plans (2) ....................................
ARO liability (3).....................................................
Gas balancing liability (4) ......................................
Repurchase obligations (5) .....................................
Workers’ compensation liability (6)........................
Capital lease obligations (7) ...................................
$
Derivative liabilities—commodity hedges............ $
$
Other......................................................................

4,244

9,886

98,297

5,047

—

16,551

22,466

285

410

Less
Than 1
Year

Unknown

2-3
Years
(In thousands)
Unknown

1,436

Unknown

4-5
Years

After 5
Years

Unknown

3,965

55,407

9,225

29,700

Unknown

7,610

3,549

— $

2,233

7,538

285

410

1,115

8,163

— $

5,593

3,216

—

_________________________
(1) We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits,
which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record
a liability, included in other long-term liabilities in our Consolidated Balance Sheets, at the time of deferral.

(2) Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible employees whose employment

with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to
receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive
payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a
Separation Benefit Plan for Senior Management (Senior Plan). The Senior Plan provides certain officers and key executives of the company with benefits
generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the
individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special Plan). This plan is identical to the
Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years
with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue
Code of 1986, as amended. On December 8, 2015, we amended the Plans to change the calculation for determining the payouts at the time of a Separation
of Service under the Plans.

(3) When a well is drilled or acquired, under ASC 410 “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with

the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

(4) We have recorded a liability for those properties we believe do not have sufficient oil, NGLs, and natural gas reserves to allow the under-produced owners

to recover their under-production from future production volumes.

(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the
Partnerships) with certain qualified employees, officers and directors from 1984 through 2011, with a subsidiary of ours serving as general partner.
Effective December 31, 2014, The Unit 1984 Oil and Gas Limited Partnership dissolved. The Partnerships were formed for the purpose of conducting oil
and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed
during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions
commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership
agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the
future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $118,000, $45,000, and $16,000 in 2015, 2014,
and 2013, respectively.

(6) We have recorded a liability for future estimated payments related to workers’ compensation claims primarily associated with our contract drilling

segment.

(7) This amount includes commitments under capital lease arrangements for compressors in our mid-stream segment.

Derivative Activities

Periodically we enter into derivative transactions locking in the prices to be received for a portion of our oil, NGLs, and
natural gas production. In August 2012, we determined–on a prospective basis–that we would no longer elect to use cash flow
hedge accounting for our economic hedges. All of our previous cash flow hedges expired as of December 31, 2013. Any change
in fair value on all commodity derivatives we have entered into are reflected in the statement of operations and not in
accumulated other comprehensive income.

Commodity Derivatives. Our commodity derivatives is intended to reduce our exposure to price volatility and manage
price risks. Our decision on the type and quantity of our production and the price(s) of our derivative(s) is based, in part, on our
view of current and future market conditions. As of December 31, 2015, based on our fourth quarter 2015 average daily
production, the approximated percentages of our production under derivative contracts are as follows:

Daily oil production...................................................................................................................

Daily natural gas production .....................................................................................................

Mark-to-Market

2016

2017

33%

52%

With respect to the commodities subject to derivative contracts, those contracts serve to limit the risk of adverse
downward price movements. However, they also limit increases in future revenues that would otherwise result from price
movements above the contracted prices.

The use of derivative transactions carries with it the risk that the counterparties may not be able to meet their financial

obligations under the transactions. Based on our evaluation at December 31, 2015, we believe the risk of non-performance by
our counterparties is not material. At December 31, 2015, the fair values of the net assets we had with each of the counterparties
to our commodity derivative transactions are as follows:

December 31, 2015

(In millions)

Canadian Imperial Bank of Commerce ........................................................................................................

Bank of Montreal .........................................................................................................................................

Scotiabank ....................................................................................................................................................

Bank of America Merrill Lynch...................................................................................................................

Total assets ...................................................................................................................................................

8.7

1.1

0.7

0.4

10.9

If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our

Consolidated Balance Sheets. At December 31, 2015, we recorded the fair value of our commodity derivatives on our balance
sheet as current and non-current derivative assets of $10.2 million and $1.0 million, respectively, and non-current derivative
liabilities of $0.3 million. At December 31, 2014, we recorded the fair value of our commodity derivatives on our balance sheet
as current derivative assets of $31.1 million.

For our economic hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before

their maturity (i.e., temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and
hedge ineffectiveness, net in our Consolidated Statements of Operations. The commodity derivative instruments we had under
cash flow accounting expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow
hedges, to the extent they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the
hedged item was recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and
natural gas revenues. Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not
designated as hedges and hedge ineffectiveness, net.

These gains (losses) are as follows at December 31:

Gain (loss) on derivatives not designated as hedges and hedge

ineffectiveness, net:

Gain (loss) on derivatives not designated as hedges, included are amounts

settled during the period of $46,615, ($6,038), and ($1,764), respectively ....

Gain (loss) on ineffectiveness of cash flow hedges ...............................................

2015

2014

2013

(In thousands)

26,345

—

26,345

30,147

—

30,147

(8,184)
(190)
(8,374)

Stock and Incentive Compensation

During 2015, we granted awards covering 750,290 shares of restricted stock. These awards were granted as retention

incentive awards. These stock awards had an estimated fair value as of the grant date of $24.5 million. Compensation expense
will be recognized over the awards' three year vesting period. During 2015, we recognized $7.9 million in additional
compensation expense and capitalized $1.9 million for these awards. During 2014, we granted awards covering 468,890 shares
of restricted stock. These awards were granted as retention incentive awards and are being recognized over the awards' three
year vesting period. During 2013, we granted awards covering 474,677 shares of restricted stock. These awards were granted as
retention incentive awards and are being recognized over their two and three year vesting periods. No SAR awards were made
during 2015, 2014, or 2013.

During 2015, we recognized compensation expense of $15.3 million for our restricted stock grants and capitalized $3.5

million of compensation cost for oil and natural gas properties. Recognized compensation expense and capitalized stock
compensation cost for oil and natural gas properties were reduced $3.2 million and $0.2 million, respectively, for adjustments
made related to the performance shares.

Insurance

We are self-insured for certain losses relating to workers’ compensation, control of well, and employee medical
benefits. Insured policies for other coverages contain deductibles or retentions per occurrence that range from zero to $1.0
million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to
certain types of claims. However, there is no assurance that the insurance coverages we have will adequately protect us against
liability from all potential consequences. Unit Texas Drilling, L.L.C. was merged into its parent company, Unit Drilling
Company, effective October 31, 2015, at which time the ERISA governed occupational injury benefit program was closed. All
new claims after this date are processed under an existing insured workers’ compensation program. If insurance coverage
becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination of these
rather than pay higher premiums.

Oil and Natural Gas Limited Partnerships and Other Entity Relationships.

We are the general partner of 15 oil and natural gas partnerships which were formed privately or publicly. Each

partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for
contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and
well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated
third parties for similar services. General and administrative reimbursements consist of direct general and administrative
expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based
on the related party’s level of activity and are considered by us to be reasonable. During 2015, 2014, and 2013, the total we
received for all of these fees was $0.4 million, $0.5 million, and $0.5 million, respectively. Our proportionate share of assets,
liabilities, and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements.

Effects of Inflation

The effect of inflation in the oil and natural gas industry is primarily driven by the prices for oil, NGLs, and natural gas.
Increases in these prices increase the demand for our contract drilling rigs and services. This increase in demand in turn affects
the dayrates we can obtain for our contract drilling services. During periods of higher demand for our drilling rigs we have
experienced increases in labor costs as well as the costs of services to support our drilling rigs. Historically, during this same
period, when oil, NGLs, and natural gas prices did decline, labor rates did not come back down to the levels existing before the
increases. If commodity prices increase substantially for a long period, shortages in support equipment (such as drill pipe, third
party services, and qualified labor) can result in additional increases in our material and labor costs. Increases in dayrates for
drilling rigs also increase the cost of our oil and natural gas properties. How inflation will affect us in the future will depend on
increases, if any, realized in our drilling rig rates, the prices we receive for our oil, NGLs, and natural gas, and the rates we
receive for gathering and processing natural gas.

Off-Balance Sheet Arrangements

We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and
capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we are subject to
various contractual commitments.

Results of Operations

2015 versus 2014

2015

2014

(In thousands unless otherwise
specified)

Percent
Change (1)

Total operating revenue .......................................................................................................
Net income (loss).................................................................................................................

Oil and Natural Gas:

Revenue .......................................................................................................................
Operating costs excluding depreciation, depletion, amortization, and impairment ....
Depreciation, depletion, and amortization...................................................................
Impairment of oil and gas properties ...........................................................................

Average oil price received (Bbl)..................................................................................
Average NGL price received (Bbl)..............................................................................
Average natural gas price received (Mcf)....................................................................
Oil production (Bbl) ....................................................................................................
NGLs production (Bbl)................................................................................................
Natural gas production (Mcf) ......................................................................................
Depreciation, depletion, and amortization rate (Boe)..................................................

Contract Drilling:

Revenue .......................................................................................................................
Operating costs excluding depreciation and impairment.............................................
Depreciation.................................................................................................................
Impairment of contract drilling equipment..................................................................

Percentage of revenue from daywork contracts...........................................................
Average number of drilling rigs in use ........................................................................
Average dayrate on daywork contracts........................................................................

Mid-Stream:

Revenue .......................................................................................................................
Operating costs excluding depreciation, amortization, and impairment .....................
Depreciation and amortization.....................................................................................
Impairment of gas gathering and processing systems .................................................

Gas gathered—Mcf/day...............................................................................................
Gas processed—Mcf/day.............................................................................................
Gas liquids sold—gallons/day .....................................................................................

Corporate and other:
General and administrative expense ....................................................................................
Gain (loss) on disposition of assets .....................................................................................
Other income (expense):......................................................................................................
Interest expense, net.....................................................................................................
Gain on derivatives not designated as hedges and hedge ineffectiveness, net ............
Other ............................................................................................................................
Income tax expense (benefit)...............................................................................................
Average interest rate ............................................................................................................
Average long-term debt outstanding....................................................................................

$
$

$
$
$
$

$
$
$

$
$
$
$

$
$

$
$
$
$

854,231
(1,037,361)

385,774
166,046
251,944
1,599,348

50.79
10.12
2.63
3,783,000
5,274,000
65,546,000
12.30

265,668
156,408
56,135
8,314

100%
34.7
19,455

202,789
161,556
43,676
26,966

353,771
182,684
577,513

35,345
(7,229)

(31,963)
26,345
45
(626,948)

5.4%

897,391

$
$

$
$
$
$

$
$
$

$
$
$
$

$
$

$
$
$
$

_________________________
(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

1,572,944
136,276

740,079
187,916
276,088
76,683

89.43
30.95
3.92
3,844,000
4,628,000
58,854,000
14.82

476,517
274,933
85,370
74,318

100%
75.4
20,043

356,348
306,831
40,434
7,068

319,348
161,282
733,406

(46)%
NM

(48)%
(12)%
(9)%
NM

(43)%
(67)%
(33)%
(2)%
14 %
11 %
(17)%

(44)%
(43)%
(34)%
(89)%

(54)%
(3)%

(43)%
(47)%
8 %
NM

11 %
13 %
(21)%

42,023
8,953

(16)%
(181)%

(17,371)
30,147
(70)
86,663

6.5%

674,832

84 %
(13)%
164 %
NM
(17)%
33 %

Oil and Natural Gas

Oil and natural gas revenues decreased $354.3 million or 48% in 2015 as compared to 2014 due primarily to lower oil,

natural gas, and NGLs prices partially offset by an increase in production. Oil production decreased 2%, NGLs production
increased 14%, and natural gas production increased 11%. Average oil prices between the comparative years decreased 43% to
$50.79 per barrel, NGLs prices decreased 67% to $10.12 per barrel, and natural gas prices decreased 33% to $2.63 per Mcf.

Oil and natural gas operating costs decreased $21.9 million or 12% between the comparative years of 2015 and 2014 due

to lower gross production taxes due to lower sales revenue and lower general and administrative expense.

Depreciation, depletion, and amortization (DD&A) decreased $24.1 million or 9% primarily due to a 17% decrease in our

DD&A rate partially offset by the effect of a 9% increase in equivalent production. The decrease in our DD&A rate in 2015
compared to 2014 resulted primarily from the effect of the ceiling test write-downs during 2015. Our DD&A expense on our oil
and natural properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

During 2015, we recorded non-cash ceiling test write-downs of our oil and natural gas properties totaling $1.6 billion pre-

tax ($1.0 billion, net of tax) compared to a non-cash ceiling test write-down of our oil and natural gas properties of $76.7
million pre-tax ($47.7 million net of tax) in December of 2014. These write-downs were due to the inclusion of the impaired
value of the unproved properties of $114.4 million and $73.7 million in 2015 and 2014, respectively and a reduction of the 12-
month average commodity prices during each year.

Contract Drilling

Drilling revenues decreased $210.8 million or 44% in 2015 as compared to 2014. The decrease was due primarily to a
54% decrease in the average number of drilling rigs in use and a 3% decrease in the average dayrate partially offset by $29.0
million for fees on contracts terminated early in 2015. Average drilling rig utilization decreased from 75.4 drilling rigs in 2014
to 34.7 drilling rigs in 2015.

Drilling operating costs decreased $118.5 million or 43% in 2015 compared to 2014. The decrease was due primarily to

fewer drilling rigs operating. Contract drilling depreciation decreased $29.2 million or 34% also due primarily to fewer drilling
rigs operating. In December 2014, 31 drilling rigs and other drilling equipment were written down to their estimated market
value. This impairment was approximately $74.3 million pre-tax. During the second quarter of 2015, we recorded an additional
impairment of approximately $8.3 million on the drilling rigs and other equipment that was sold at auction during the third
quarter.

Several of our drilling rig customers have continued to significantly reduce their drilling budgets for 2016, resulting in a

significant reduction in the average utilization of our drilling fleet mix. At December 31, 2015, we had 26 drilling rigs
operating, at February 12, 2016, this number has been reduced to 20 drilling rigs operating.

Mid-Stream

Our mid-stream revenues decreased $153.6 million or 43% in 2015 as compared to 2014 due primarily from the average

price for NGLs sold decreasing 47%, the average price for natural gas sold decreasing 39%, and NGLs volumes sold per day
decreasing 21% primarily from being in ethane rejection mode. Gas processing volumes per day increased 13% between the
comparative years primarily from new well connections. Gas gathering volumes per day increased 11% primarily from new
well connections.

Operating costs decreased $145.3 million or 47% in 2015 compared to 2014 primarily due to an 54% decrease in prices

paid for natural gas purchased partially offset by a 12% increase in purchase volumes. Depreciation and amortization increased
$3.2 million or 8% primarily due to capital expenditures for upgrades and well connects.

In December 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 due to anticipated future cash flow and future development around these systems supporting their
carrying value. The estimated future cash flows were less than the carrying value on these systems. In December 2015, our mid-
stream segment had another $27.0 million pre-tax write-down of three of its systems, Bruceton Mills, Midwell, and Spring
Creek 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.

Due to the decline in NGLs prices beginning in 2014, we operated our processing facilities in full ethane rejection mode

which reduced the amount of liquids sold throughout 2015. As long as NGLs prices continue at or below these levels,we expect
to continue operating in full ethane rejection mode. Our mid-stream segment did not experience a reduction in processed
volumes in 2015 but as low prices continue we expect further reductions in drilling activity around our systems which will
eventually effect our ability to connect new wells resulting in lower processed volumes in the future.

General and Administrative

General and administrative expenses decreased $6.7 million or 16% in 2015 compared to 2014 primarily due to lower

employee costs and a $1.8 million decrease in the stock-based compensation accrual due to an evaluation of the performance
based shares component of previous grants.

Gain (loss) on Disposition of Assets

Gain (loss) on disposition of assets decreased $16.2 million in 2015 compared to 2014 primarily due to the loss of $7.3
million pre-tax on the sale of 30 drilling rigs and other drilling equipment in an auction somewhat offset by the gains on the sale
of one gathering system, various drilling rig components, vehicles, and a drilling rig during 2015, compared to a gain of $9.0
million primarily for the sale of four idle 3,000 horsepower drilling rigs to an unaffiliated third-party during 2014.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $14.6 million between the comparative years of 2015 and 2014. We

capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of
additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2015 was $21.7 million compared
to $32.2 million in 2014, and was netted against our gross interest of $53.7 million and $49.6 million for 2015 and 2014,
respectively. Our average interest rate decreased from 6.5% to 5.4% and our average debt outstanding was $222.6 million
higher in 2015 as compared to 2014 primarily due to the increase in our outstanding borrowings under our credit agreement
over the comparative periods.

Gain on derivatives not designated as hedges decreased from a gain of $30.1 million in 2014 to a gain of $26.3 million in

2015 primarily due to fluctuations in forward prices used to estimate the fair value in mark-to-market accounting.

Income Tax Expense

Income tax expense decreased $713.6 million in 2015 compared to 2014 primarily due to decreased income due to the
impairments in all three segments during 2015. Our effective tax rate was 37.7% for 2015 and 38.9% for 2014. This decrease is
primarily due to the effect of permanent differences as they relate to negative pre-tax income. Current income tax benefit was
$20.6 million in 2015 compared to a current income tax expense of $9.4 million for 2014. The $20.6 million current income tax
benefit is due to an anticipated alternative minimum tax (AMT) net operating loss (NOL) refund. We paid $3.5 million in
income taxes during 2015.

2014 versus 2013

2014

2013

(In thousands unless otherwise
specified)

Percent
Change (1)

Total operating revenue .......................................................................................................

Net income...........................................................................................................................

Oil and Natural Gas:

Revenue .......................................................................................................................

Operating costs excluding depreciation, depletion, amortization, and impairment ....

Depreciation, depletion, and amortization...................................................................

Impairment of oil and natural gas properties...............................................................

Average oil price received (Bbl)..................................................................................

Average NGLs price received (Bbl) ............................................................................

Average natural gas price received (Mcf)....................................................................

Oil production (Bbl) ....................................................................................................

NGLs production (Bbl)................................................................................................

Natural gas production (Mcf) ......................................................................................

Depreciation, depletion, and amortization rate (Boe)..................................................

Contract Drilling:

Revenue .......................................................................................................................

Operating costs excluding depreciation and impairment.............................................

Depreciation.................................................................................................................

Impairment of contract drilling equipment..................................................................

Percentage of revenue from daywork contracts...........................................................

Average number of drilling rigs in use ........................................................................

Average dayrate on daywork contracts........................................................................

Mid-Stream:

Revenue .......................................................................................................................

Operating costs excluding depreciation, amortization, and impairment .....................

Depreciation and amortization.....................................................................................

Impairment of gas gathering and processing systems .................................................

Gas gathered—Mcf/day...............................................................................................

Gas processed—Mcf/day.............................................................................................

Gas liquids sold—gallons/day .....................................................................................

Corporate and other:

General and administrative expense ....................................................................................

Gain on disposition of assets ...............................................................................................

Other income (expense):......................................................................................................

Interest expense, net.....................................................................................................

Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net ..

Other ............................................................................................................................

Income tax expense..............................................................................................................

Average interest rate ............................................................................................................

Average long-term debt outstanding....................................................................................

1,572,944

136,276

740,079

187,916

276,088

76,683

89.43

30.95

3.92

3,844,000

4,628,000

58,854,000

14.82

476,517

274,933

85,370

74,318

100%

75.4

20,043

356,348

306,831

40,434

7,068

319,348

161,282

733,406

42,023

8,953

(17,371)

30,147

(70)

86,663

6.5%

674,832

_________________________
(1) NM – A percentage calculation is not meaningful due to a zero-value denominator or a percentage change greater than 200.

1,351,850

184,746

16 %

(26)%

649,718

184,001

226,498

—

95.06

31.79

3.32

3,360,000

3,914,000

56,757,000

13.32

414,778

247,280

71,194

—

100%

65.0

19,646

287,354

243,406

33,191

—

309,554

140,584

543,602

38,323

17,076

(15,015)

(8,374)

(175)

116,723

6.4%

686,656

14 %

2 %

22 %

(6)%

(3)%

18 %

14 %

18 %

4 %

11 %

15 %

11 %

20 %

16 %

2 %

24 %

26 %

22 %

3 %

15 %

35 %

10 %

(48)%

16 %

(60)%

(26)%

2 %

(2)%

Oil and Natural Gas

Oil and natural gas revenues increased $90.4 million or 14% in 2014 as compared to 2013 primarily due to a 9% increase
in equivalent production volumes. Oil production increased 14%, NGLs production increased 18%, and natural gas production
increased 4%. Average oil prices between the comparative years decreased 6% to $89.43 per barrel and NGLs prices decreased
3% to $30.95 per barrel while prices for natural gas increased 18% to $3.92 per Mcf.

Oil and natural gas operating costs increased $3.9 million or 2% between the comparative years of 2014 and 2013 due to
increased lease operating costs, higher saltwater disposal expenses, and increased general and administrative expense partially
offset by lower gross production tax due to tax credits.

DD&A increased $49.6 million or 22% primarily due to an 9% increase in equivalent production and an 11% increase in
our DD&A rate. The increase in our DD&A rate in 2014 compared to 2013 resulted primarily from increased capitalized cost
on new wells drilled between periods. Our DD&A expense on our oil and natural gas properties is calculated each quarter
utilizing period end reserve quantities adjusted for current period production.

In December 2014, we determined the value of certain unproved oil and gas properties were diminished (in part or in

whole) based on an impairment evaluation and our anticipated future exploration plans. That determination resulted in $73.7
million of costs associated with the unproved properties being added to the capitalized costs to be amortized. We incurred a
non-cash ceiling test write-down of our oil and natural gas properties of $76.7 million pre-tax ($47.7 million net of tax). We did
not have any ceiling test write-downs during 2013.

Contract Drilling

Drilling revenues increased $61.7 million or 15% in 2014 as compared to 2013. The increase was due primarily to a 16%
increase in the average number of drilling rigs in use and a 2% increase in the average dayrate. Average drilling rig utilization
increased from 65.0 drilling rigs in 2013 to 75.4 drilling rigs in 2014.

Drilling operating costs increased $27.7 million or 11% in 2014 compared to 2013. The increase was due primarily to
higher direct and indirect expenses due to higher utilization. Contract drilling depreciation and impairment increased $88.5
million or 124% due primarily to the write-down of 31 drilling rigs and other assets and to a lesser extent the increase in
utilization.

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. We estimated the fair value of the drilling rigs and other assets based on the estimate
market value from third-party assessments. Based on these estimates, we recorded a write-down of approximately $74.3 million
pre-tax.

Mid-Stream

Our mid-stream revenues increased $69.0 million or 24% in 2014 as compared to 2013. The average price for natural gas

sold increased 15%. Gas processing volumes per day increased 15% between the comparative years and NGLs sold per day
increased 35% between the comparative periods. The increase in volumes processed per day is primarily attributable to the
volumes added from new wells connected to existing systems and increased capacity of processing facilities. Gas gathering
volumes per day increased 3% primarily from new well connections.

Operating costs increased $63.4 million or 26% in 2014 compared to 2013 primarily due to an 8% increase in prices paid

for natural gas purchased. Depreciation, amortization, and impairment increased $14.3 million or 43% primarily due to the
write-down of three systems and additional assets placed into service throughout 2013.

In December 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 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.

Due to the decline in NGLs prices during 2014, in the second half of the year we operated our processing facilities in full
ethane rejection mode which reduced the amount of liquids sold during this time period. As long as NGLs prices continue at or

below these levels,we expect to continue operating in full ethane rejection mode. Our mid-stream segment did not experience a
significant reduction in processed volumes in 2014 but as low prices continue we expect further reductions in drilling activity
around our systems which will eventually effect our ability to connect new wells resulting in lower processed volumes in the
future.

General and Administrative

General and administrative expenses increased $3.7 million or 10% in 2014 compared to 2013. The increase was

primarily due to increases in employee costs.

Gain on Disposition of Assets

Gain on disposition of assets decreased $8.1 million in 2014 compared to 2013 primarily due to the sale of fewer drilling

rigs.

Other Income (Expense)

Interest expense, net of capitalized interest, increased $2.4 million between the comparative years of 2014 and 2013. We

capitalized interest based on the net book value associated with unproved properties not being amortized, the construction of
additional drilling rigs, and the construction of gas gathering systems. Capitalized interest for 2014 was $32.2 million compared
to $33.7 million in 2013, and was netted against our gross interest of $49.6 million and $48.7 million for 2014 and 2013,
respectively. Our average interest rate increased from 6.4% to 6.5% and our average debt outstanding was $11.8 million lower
in 2014 as compared to 2013 primarily due to the reduction of outstanding borrowings under our credit agreement over the
comparative periods.

Gain (loss) on derivatives not designated as hedges and hedge ineffectiveness, net increased from a loss of $8.4 million in

2013 to a gain of $30.1 million in 2014 primarily due to fluctuations in forward prices used to estimate the fair value in mark-
to-market accounting.

Income Tax Expense

Income tax expense decreased $30.1 million in 2014 compared to 2013 primarily due to decreased income due to the
impairments in all three segments during 2014. Our effective tax rate was 38.9% for 2014 and 38.7% for 2013. This increase is
primarily due to the effect of permanent differences as they relate to the decline in pre-tax income. Current income tax expense
was $9.4 million in 2014 compared to a current income tax expense of $16.0 million for 2013. This decrease is also primarily
due to decreased income. We paid $15.9 million in income taxes during 2014.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Our operations are exposed to market risks primarily as a result of changes in the prices for natural gas and oil and interest

rates.

Commodity Price Risk. Our major market risk exposure is in the prices we receive for our oil, NGLs, and natural gas

production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to
our natural gas production. Historically, these prices have fluctuated and we expect they will continue to do so. The price of oil,
NGLs, and natural gas also affects both the demand for our drilling rigs and the amount we can charge for the use of our
drilling rigs. Based on our 2015 production, a $0.10 per Mcf change in what we are paid for our natural gas production would
result in a corresponding $520,000 per month ($6.2 million annualized) change in our pre-tax cash flow. A $1.00 per barrel
change in our oil price would have a $303,000 per month ($3.6 million annualized) change in our pre-tax operating cash flow
and a $1.00 per barrel change in our NGLs prices would have a $419,000 per month ($5.0 million annualized) change in our
pre-tax cash flow.

We use derivative transactions to manage the risk associated with price volatility. Our decision on the type and quantity of

our production and the price(s) of our derivative(s) is based, in part, on our view of current and future market conditions. The
transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a
variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading
purposes.

At December 31, 2015, the following non-designated hedges were outstanding:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price for Swaps

Contracted Market

Jan’16 – Dec’16

Natural gas – swap

35,000 MMBtu/day

$2.625

Natural gas – collar

42,000 MMBtu/day

$2.40 - $2.88

IF – NYMEX (HH)

Jan’16 – Dec'16

Jan’17 – Dec'17

Jan’16 – Jun'16

Jul’16 – Dec'16

Jan’16 – Dec'16

Jul’16 – Dec'16

Jan’17 – Dec'17

Natural gas – three-way collar

13,500 MMBtu/day

$2.70 - $2.20 - $3.26

IF – NYMEX (HH)

Natural gas – three-way collar

15,000 MMBtu/day

$2.50 - $2.00 - $3.32

IF – NYMEX (HH)

Crude oil – collar

2,150 Bbl/day

1,450 Bbl/day

$46.36 - $55.62

$47.50 - $56.40

WTI – NYMEX

Crude oil – three-way collar

700 Bbl/day

$46.50 - $35.00 - $57.00

WTI – NYMEX

Crude oil – three-way collar (1)

700 Bbl/day

$47.50 - $35.00 - $63.50

WTI – NYMEX

Crude oil – three-way collar

750 Bbl/day

$50.00 - $37.50 - $63.90

WTI – NYMEX

_________________________
(1) We pay our counterparty a premium, which can be and is being deferred until settlement.

Subsequent to December 31, 2015, the following non-designated hedges were entered into:

Term

Commodity

Contracted Volume

Weighted Average
Fixed Price for Swaps

Contracted Market

Feb’16 – Dec'16

Natural gas – swap

Jan’17 – Dec'17

Natural gas – swap

10,000 MMBtu/day

$2.495

$2.795

IF – NYMEX (HH)

Interest Rate Risk. Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The

credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election,
borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Based on our average
outstanding long-term debt subject to a variable rate in 2015, a 1% increase in the floating rate would reduce our annual pre-tax
cash flow by approximately $2.5 million. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-
annually in arrears on May 15 and November 15 of each year).

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements
Unit Corporation and Subsidiaries

Management’s Report on Internal Control over Financial Reporting.....................................................................
Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm ............................................................................
Consolidated Balance Sheets at December 31, 2015 and 2014 .......................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014, and 2013................
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2015, 2014,
and 2013........................................................................................................................................................

Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2013,

2014, and 2015..............................................................................................................................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013..............
Notes to Consolidated Financial Statements....................................................................................................

Page

Management’s Report on Internal Control over Financial Reporting

Management of the company is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in Rules 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal
financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles and includes those policies and procedures that:

•

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and
dispositions of the assets of the company;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements
in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition
of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because
of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance
and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting
also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that
material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting.
However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into
the process safeguards to reduce, though not eliminate, this risk.

The company’s management assessed the effectiveness of the company’s internal control over financial reporting as of

December 31, 2015. In making this assessment, the company’s management used the criteria set forth in Internal Control—
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on their assessment, the company’s management concluded that, as of December 31, 2015, the company’s internal
control over financial reporting was effective based on those criteria.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2015, has been audited

by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears
herein.

Report of Independent Registered Public Accounting Firm

To Board of Directors and Shareholders of Unit Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations,
comprehensive income (loss), changes in shareholders’ equity, and cash flows present fairly, in all material respects, the
financial position of Unit Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their operations
and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting
principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed
in the index appearing under Item 15(a)(2), presents fairly, in all material respects, the information set forth therein when read
in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company's management is responsible for these financial statements and financial statement schedule, for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our
responsibility is to express opinions on these financial statements, on the financial statement schedule and on the Company's
internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma
February 25, 2016

As of December 31,

2015

2014

(In thousands except share and par
value amounts)

835

1,049

79,941
3,565
10,186
21,002
14,206
615
9,908
140,258

5,401,618
337,099
1,567,560
689,063
60,316
49,890
40,072
45,489
8,191,107
5,609,980
2,581,127
8,667
62,808
968
14,681
2,808,509

189,812
5,590
31,139
—
11,527
—
13,374
252,491

4,990,753
485,568
1,620,692
628,689
56,702
16,104
40,693
41,602
7,880,803
3,747,412
4,133,391
10,255
62,808
—
14,783
4,473,728

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

Current assets:

ASSETS

Cash and cash equivalents..................................................................................................
Accounts receivable (less allowance for doubtful accounts of $5,199 and $5,039 at

December 31, 2015 and 2014, respectively) ..................................................................
Materials and supplies ........................................................................................................
Current derivative asset (Note 12) .....................................................................................
Current income tax receivable............................................................................................
Current deferred tax asset (Note 8) ....................................................................................
Assets held for sale (Note 2) ..............................................................................................
Prepaid expenses and other ................................................................................................
Total current assets ............................................................................................

Property and equipment:

Oil and natural gas properties, on the full cost method:

Proved properties ........................................................................................................
Unproved properties not being amortized...................................................................
Drilling equipment .............................................................................................................
Gas gathering and processing equipment...........................................................................
Saltwater disposal systems .................................................................................................
Corporate land and building ...............................................................................................
Transportation equipment...................................................................................................
Other...................................................................................................................................

Less accumulated depreciation, depletion, amortization, and impairment ........................
Net property and equipment ..............................................................................
Debt issuance cost .....................................................................................................................
Goodwill (Note 2)......................................................................................................................
Non-current derivative asset (Note 12) .....................................................................................
Other assets................................................................................................................................
Total assets.................................................................................................................................

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (Continued)

As of December 31,

2015

2014

(In thousands except share and par
value amounts)

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:

Accounts payable ............................................................................................................... $
Accrued liabilities (Note 5) ................................................................................................
Income taxes payable .........................................................................................................
Current portion of other long-term liabilities (Note 6) ......................................................
Total current liabilities.......................................................................................
Long-term debt (Note 6)............................................................................................................
Non-current derivative liabilities (Note 12) ..............................................................................
Other long-term liabilities (Note 6)...........................................................................................
Deferred income taxes (Note 8) ................................................................................................
Commitments and contingencies (Note 15) ..............................................................................
Shareholders’ equity:

87,413
46,918
—
16,560
150,891
927,662
285
140,341
275,750
—

218,500
70,171
481
15,019
304,171
812,163
—
148,785
876,215
—

Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued .....................
Common stock, $0.20 par value, 175,000,000 shares authorized, 50,413,101 and

49,593,812 shares issued as of December 31, 2015 and 2014, respectively ..................
Capital in excess of par value.............................................................................................
Retained earnings ...............................................................................................................
Total shareholders’ equity....................................................................................
Total liabilities and shareholders’ equity...................................................................................

—

9,831
486,571
817,178
1,313,580
2,808,509

9,732
468,123
1,854,539
2,332,394
4,473,728

The accompanying notes are an integral part of the consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

Year Ended December 31,

2015

2014
(In thousands except per share amounts)

2013

Revenues:

Oil and natural gas ..................................................................................
Contract drilling......................................................................................
Gas gathering and processing .................................................................
Total revenues..................................................................................

385,774
265,668
202,789
854,231

740,079
476,517
356,348
1,572,944

649,718
414,778
287,354
1,351,850

Expenses:

Oil and natural gas:

Operating costs ................................................................................
Depreciation, depletion, and amortization.......................................
Impairment of oil and natural gas properties (Note 2) ....................

Contract drilling:

Operating costs ................................................................................
Depreciation ....................................................................................
Impairment of contract drilling equipment (Note 2) .......................

Gas gathering and processing:

Operating costs ................................................................................
Depreciation and amortization ........................................................
Impairment of gas gathering and processing systems (Note 2).......
General and administrative .....................................................................
(Gain) loss on disposition of assets ........................................................
Total expenses .................................................................................
Income (loss) from operations .......................................................................
Other income (expense):

Interest, net .............................................................................................
Gain (loss) on derivatives not designated as hedges and hedge

ineffectiveness, net..............................................................................
Other .......................................................................................................
Total other income (expense) ..........................................................
Income (loss) before income taxes ................................................................
Income tax expense (benefit):

Current ....................................................................................................
Deferred ..................................................................................................
Total income taxes...........................................................................
Net income (loss) ...........................................................................................
Net income (loss) per common share:

Basic .......................................................................................................
Diluted ....................................................................................................

166,046
251,944
1,599,348

156,408
56,135
8,314

161,556
43,676
26,966
35,345
7,229
2,512,967
(1,658,736)

187,916
276,088
76,683

274,933
85,370
74,318

306,831
40,434
7,068
42,023
(8,953)
1,362,711
210,233

184,001
226,498
—

247,280
71,194
—

243,406
33,191
—
38,323
(17,076)
1,026,817
325,033

(31,963)

(17,371)

(15,015)

26,345
45
(5,573)
(1,664,309)

(20,616)
(606,332)
(626,948)
(1,037,361) $

30,147
(70)
12,706
222,939

9,378
77,285
86,663
136,276

(21.12) $
(21.12) $

2.80
2.78

$
$

(8,374)
(175)
(23,564)
301,469

15,991
100,732
116,723
184,746

3.83
3.80

The accompanying notes are an integral part of the consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For Years ended December 31,

Net income (loss) ...........................................................................................

Other comprehensive income (loss), net of taxes:

Change in value of derivative instruments used as cash flow hedges,

net of tax of $0, $0, and ($4,717)........................................................

Reclassification - derivative settlements, net of tax of $0, $0, and

($249) ..................................................................................................

Ineffective portion of derivatives, net of tax of $0, $0, and $74 ............

2015

(1,037,361) $

2014
(In thousands)
136,276

2013

184,746

—

(7,349)

(354)
116

Comprehensive income (loss)........................................................................

(1,037,361) $

136,276

177,159

The accompanying notes are an integral part of the consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
Year Ended December 31, 2013, 2014, and 2015

Common
Stock

Capital
In Excess
of Par Value

Accumulated
Other
Comprehensive
Income

Retained
Earnings

Total

(In thousands except share amounts)

Balances, January 1, 2013 ......................

9,594

423,603

7,587

1,533,517

1,974,301

Comprehensive income:

Net income ......................................
Other comprehensive loss (net of

tax ($4,892)) ................................
Total comprehensive income......

Activity in employee compensation

plans (525,056 shares)......................
Balances, December 31, 2013 ................
Net income ...........................................
Activity in employee compensation

plans (486,808 shares)......................
Balances, December 31, 2014 ................
Net income (loss) .................................
Activity in employee compensation

plans (819,289 shares)......................
Balances, December 31, 2015 ................

—

65
9,659
—

73
9,732
—

99
9,831

—

21,867
445,470
—

22,653
468,123
—

—

184,746

(7,587)

—

(7,587)
177,159

21,932
2,173,392
136,276

—
1,718,263
136,276

—
1,854,539
(1,037,361)

22,726
2,332,394
(1,037,361)

—
—
—

18,448
486,571

—
— $

—
817,178

18,547
1,313,580

The accompanying notes are an integral part of the consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

2015

Year Ended December 31,
2014
(In thousands)

2013

(1,037,361) $

136,276

184,746

OPERATING ACTIVITIES:

Net income (loss) ................................................................................................
Adjustments to reconcile net income (loss) to net cash provided (used) by

operating activities:

Depreciation, depletion, and amortization................................................
Impairment of properties (Note 2)............................................................
(Gain) loss on derivatives .........................................................................
Cash (payments) receipts on derivatives settled.......................................
(Gain) loss on disposition of assets ..........................................................
Deferred tax expense (benefit) .................................................................
Employee stock compensation plans........................................................
Bad debt expense ......................................................................................
ARO liability accretion.............................................................................
Other, net ..................................................................................................

Changes in operating assets and liabilities increasing (decreasing) cash:

Accounts receivable..................................................................................
Materials and supplies ..............................................................................
Prepaid expenses and other.......................................................................
Accounts payable......................................................................................
Accrued liabilities.....................................................................................
Contract advances.....................................................................................
Net cash provided by operating activities.........................................

INVESTING ACTIVITIES:

Capital expenditures............................................................................................
Producing property and other acquisitions..........................................................
Proceeds from disposition of property and equipment........................................
Other....................................................................................................................
Net cash used in investing activities.................................................

FINANCING ACTIVITIES:

Borrowings under line of credit ..........................................................................
Payments under line of credit..............................................................................
Payments on capitalized leases ...........................................................................
Proceeds from exercise of stock options .............................................................
Tax (expense) benefit from stock compensation.................................................
Increase (decrease) in book overdrafts (Note 2) .................................................
Net cash provided by (used in) financing activities .........................
Net increase (decrease) in cash and cash equivalents .................................................
Cash and cash equivalents, beginning of year.............................................................
Cash and cash equivalents, end of year.......................................................................

Supplemental disclosure of cash flow information:

Cash paid during the year for:

Interest paid (net of capitalized) ...............................................................
Income taxes .............................................................................................

Changes in accounts payable and accrued liabilities related to purchases of

property, plant, and equipment........................................................................

Non-cash reductions to oil and natural gas properties related to asset

retirement obligations......................................................................................

Non-cash additions to property, plant, and equipment acquired under capital

leases ...............................................................................................................

$
$

354,830
1,634,628
(26,345)
46,615
7,229
(606,332)
21,468
1,191
3,453
(1,517)

105,426
1,507
(14,348)
(20,306)
(22,920)
(274)
446,944

(561,453)
(179)
11,854
—
(549,778)

618,500
(503,500)
(3,549)
—
(3,207)
(5,624)
102,620
(214)
1,049
835

30,910
3,540

105,157

5,694

$
$

404,943
158,069
(30,147)
(6,038)
(8,953)
77,285
24,320
3,562
4,599
1,068

(60,800)
2,602
(444)
4,715
(1,297)
(767)
708,993

(981,374)
(5,723)
66,197
303
(920,597)

725,800
(559,800)
(2,392)
1,083
1,614
27,755
194,060
(17,544)
18,593
1,049

13,620
15,898

$
$

333,907
—
7,771
(1,161)
(17,076)
100,732
21,317
—
5,450
2,250

2,967
(2,435)
1,813
15,715
17,198
1,137
674,331

(703,984)
—
120,910
3,894
(579,180)

222,500
(293,600)
—
574
8
(7,014)
(77,532)
17,619
974
18,593

12,485
9,100

(31,968) $

(6,550)

37,689

17,952

— $

(28,202) $

—

The accompanying notes are an integral part of the consolidated financial statements.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION

Unless the context clearly indicates otherwise, references in this report to “Unit”, “Company”, “we”, “our”, “us”, or like

terms refer to Unit Corporation and its subsidiaries.

We are primarily engaged in the exploration, development, acquisition, and production of oil and natural gas properties,
the land contract drilling of natural gas and oil wells, and the buying, selling, gathering, processing, and treating of natural gas.
Our operations are located principally in the United States and are organized in the following three reporting segments: (1) Oil
and Natural Gas, (2) Contract Drilling, and (3) Mid-Stream.

Oil and Natural Gas. Carried out by our subsidiary, Unit Petroleum Company, we explore, develop, acquire, and produce

oil and natural gas properties for our own account. Our producing oil and natural gas properties, unproved properties, and
related assets are located mainly in Oklahoma and Texas, and to a lesser extent, in Arkansas, Colorado, Kansas, Louisiana,
Mississippi, Montana, New Mexico, North Dakota, and Wyoming.

Contract Drilling. Carried out by our subsidiary, Unit Drilling Company, we drill onshore oil and natural gas wells for
our own account as well as for a wide range of other oil and natural gas companies. Our drilling operations are mainly located
in Oklahoma, Texas, Wyoming, North Dakota, and to a lesser extent in Louisiana and Kansas.

Historically, our contract drilling segment experienced more demand for natural gas drilling as opposed to drilling for oil

and NGLs. Since 2008, operators have been focusing more on drilling for oil and NGLs.

Mid-Stream. Carried out by our subsidiary, Superior Pipeline Company, L.L.C. and its subsidiaries, we buy, sell, gather,

transport, process, and treat natural gas for our own account and for third parties. Mid-stream operations are performed in
Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The consolidated financial statements include the accounts of Unit Corporation and its

subsidiaries. Our investment in limited partnerships is accounted for on the proportionate consolidation method, whereby our
share of the partnerships’ assets, liabilities, revenues, and expenses are included in the appropriate classification in the
accompanying consolidated financial statements.

Certain amounts in the accompanying consolidated financial statements for prior periods have been reclassified to
conform to current year presentation. Certain financial statement captions were expanded or combined with no impact to
consolidated net income or shareholders' equity.

Accounting Estimates. The preparation of financial statements in conformity with generally accepted accounting

principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ from those estimates.

Drilling Contracts. We recognize revenues and expenses generated from “daywork” drilling contracts as the services are
performed, since we do not bear the risk of completion of the well. Under “footage” and “turnkey” contracts, we bear the risk of
completion of the well; therefore, revenues and expenses are recognized when the well is substantially completed. Under this
method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The
entire amount of a loss, if any, is recorded when the loss is determinable. The costs of uncompleted drilling contracts include
expenses incurred to date on “footage” or “turnkey” contracts, which are still in process at the end of the period, and are
included in other current assets. Typically, any one of these three types of contracts can be used for the drilling of one well
which can take from 10 to 90 days. At December 31, 2015, all of our contracts were daywork contracts of which nine were
multi-well and had durations which ranged from six months to three years, five of which expire in 2016 and four expiring in
2017. These longer term contracts may contain a fixed rate for the duration of the contract or provide for the periodic
renegotiation of the rate within a specific range from the existing rate.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Cash Equivalents and Book Overdrafts. We include as cash equivalents all investments with maturities at date of
purchase of three months or less which are readily convertible into known amounts of cash. Book overdrafts are checks that
have been issued before the end of the period, but not presented to our bank for payment before the end of the period. At
December 31, 2015 and 2014, book overdrafts were $22.1 million and $27.8 million, respectively.

Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for
doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial
condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts
only after all collection attempts have been unsuccessful.

Financial Instruments and Concentrations of Credit Risk and Non-performance Risk. Financial instruments, which

potentially subject us to concentrations of credit risk, consist primarily of trade receivables with a variety of oil and natural gas
companies. We do not generally require collateral related to receivables. Our credit risk is considered to be limited due to the
large number of customers comprising our customer base. Below are the third-party customers that accounted for more than
10% of our segment’s revenues:

Oil and Natural Gas:

Sunoco Logistics Partners L.P................................................................

Valero Energy Corporation.....................................................................

Drilling:

QEP Resources, Inc. ...............................................................................

Whiting Petroleum Corp. (formerly Kodiak Oil and Gas Corp.) ...........

Mid-Stream:

ONEOK Partners, L.P.............................................................................

Tenaska Resources, LLC ........................................................................

Laclede Group, Inc. ................................................................................

2015

2014

2013

19%

15%

25%

29%

18%

12%

14%

24%

19%

44%

22%

16%

25%

18%

10%

57%

16%

We had a concentration of cash of $2.3 million and $18.4 million at December 31, 2015 and 2014, respectively with one

bank.

The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms

of the transactions. We considered this non-performance risk with regard to our counterparties and our own non-performance
risk in our derivative valuation at December 31, 2015 and determined there was no material risk at that time. At December 31,
2015, the fair values of the net assets we had with each of the counterparties with respect to all of our commodity derivative
transactions are listed in the table below:

Canadian Imperial Bank of Commerce ........................................................................................................

Bank of Montreal .........................................................................................................................................

Scotiabank ....................................................................................................................................................

Bank of America Merrill Lynch...................................................................................................................

Total assets ...................................................................................................................................................

8.7

1.1

0.7

0.4

10.9

December 31, 2015
(In millions)

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Property and Equipment. Drilling equipment, transportation equipment, gas gathering and processing systems, and other

property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while
repairs and maintenance are expensed. Depreciation of drilling equipment is recorded using the units-of-production method
based on estimated useful lives starting at 15 years , including a minimum provision of 20% of the active rate when the
equipment is idle. We use the composite method of depreciation for drill pipe and collars and calculate the depreciation by
footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is
computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.

We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth
quarter, or when events occur or changes in circumstances suggest that these carrying amounts may not be recoverable.
Changes that could prompt such an assessment may include equipment obsolescence, changes in the market demand for a
specific asset, changes in commodity prices, periods of relatively low drilling rig utilization, declining revenue per day,
declining cash margin per day, or overall changes in general market conditions. Assets are determined to be impaired if a
forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any,
is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by
which the carrying amount of the asset exceeds its fair value. The 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
and equipment. Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash
flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and
their effect on future utilization levels, dayrates, and costs. The use of different estimates and assumptions could result in
materially different carrying values of our assets.

As of December 31, 2015, with continuing declines to commodity prices and an outlook that commodity prices may be

On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs,
expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig
type. The components comprising inactive rigs are evaluated, and those components with continuing utility to the Company’s
other marketed rigs are transferred to other rigs or to its yards to be used as spare equipment. The remaining components of
these rigs are retired. 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 the first quarter of 2015, we sold one of these drilling
rigs to an unaffiliated third party. The proceeds of this sale, less costs to sell, exceeded the $0.3 million net book value of the
drilling rig resulting in a gain of $7,900. During the second quarter, we recorded an additional write-down on the remaining
drilling rigs and other equipment of approximately $8.3 million pre-tax based on the estimated market value from similar
auctions. During the third quarter, we sold the remaining 30 drilling rigs and most of the equipment in an auction. The proceeds
from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of $7.3 million
pre-tax. Some of the equipment that was not sold at the auction will be sold within the next twelve months and remain classified
as assets held for sale. The net book value of those assets is $0.6 million. When property and equipment components are
disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is
generally reflected in operations. For dispositions of drill pipe and drill collars, an average cost for the appropriate feet of drill
pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are
credited to accumulated depreciation.

In 2015, our mid-stream segment incurred a $27.0 million, pre-tax write-down of three of its systems, Bruceton Mills,

Midwell, and Spring Creek 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.

In 2014, our mid-stream segment incurred a $7.1 million, pre-tax write-down of three of its systems, Weatherford, Billy

Rose, and Spring Creek 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. No significant
impairments were recorded in 2013.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We record an asset and a liability equal to the present value of the expected future ARO associated with our oil and gas

properties. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We
measure changes in the liability due to passage of time by accreting an interest charge. This amount is recognized as an increase
in the carrying amount of the liability and as a corresponding accretion expense.

Capitalized Interest. During 2015, 2014, and 2013, interest of approximately $21.7 million, $32.2 million, and $33.7

million, respectively, was capitalized based on the net book value associated with unproved properties not being amortized, the
construction of additional drilling rigs, and the construction of gas gathering systems. Interest is being capitalized using a
weighted average interest rate based on our outstanding borrowings.

Goodwill. Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired.
Goodwill is not amortized, but an impairment test is performed at least annually to determine whether the fair value has
decreased and is performed additionally when events indicate an impairment may have occurred. For purposes of impairment
testing, goodwill is evaluated at the reporting unit level. Our goodwill is all related to our contract drilling segment, and
accordingly, the impairment test is generally based on the estimated discounted future net cash flows of our drilling segment,
utilizing discount rates and other factors in determining the fair value of our drilling segment. Inputs in our estimated
discounted future net cash flows include drilling rig utilization, day rates, gross margin percentages, and terminal value. No
goodwill impairment was recorded for the years ended December 31, 2015, 2014, or 2013. There were no additions to goodwill
in 2015, 2014, or 2013. Based on our impairment test performed as of December 31, 2015, the fair value of our drilling segment
exceeded its carrying value by 19%. Goodwill of $2.2 million is deductible for tax purposes.

Intangible Assets. Intangible assets are capitalized and amortized over the estimated period benefited. Such amounts are

reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be
recoverable. No intangible asset impairment was recorded for the years ended December 31, 2015, 2014, or 2013. Amortization
of $0.7 million was recorded 2013. Accumulated amortization for 2013 was $18.0 million. Our intangible assets became fully
amortized in 2013, so no amortization was recorded in 2014 or 2015.

Oil and Natural Gas Operations. We account for our oil and natural gas exploration and development activities using the

full cost method of accounting prescribed by the SEC. Accordingly, all productive and non-productive costs incurred in
connection with the acquisition, exploration and development of our oil, NGLs, and natural gas reserves, including directly
related overhead costs and related asset retirement costs, are capitalized and amortized on a units-of-production method based
on proved oil and natural gas reserves. Directly related overhead costs of $19.2 million, $23.7 million, and $21.5 million were
capitalized in 2015, 2014, and 2013, respectively. Independent petroleum engineers annually audit our internal evaluation of
our reserves. The average rates used for depreciation, depletion, and amortization (DD&A) were $12.30, $14.82, and $13.32
per Boe in 2015, 2014, and 2013, respectively. The calculation of DD&A includes estimated future expenditures to be incurred
in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. Our
unproved properties totaling $337.1 million are excluded from the DD&A calculation.

No gains or losses are recognized on the sale, conveyance, or other disposition of oil and natural gas properties unless a

significant reserve amount to our total reserves is involved.

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Under the full cost rules, at the end of each quarter, we review the carrying value of our oil and natural gas properties.

The full cost ceiling is based principally on the estimated future discounted net cash flows from our oil and natural gas
properties discounted at 10%. We 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. In the event the unamortized cost of oil and natural gas properties being
amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such
excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

$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. 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) in 2015 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.

Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their

timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an
ownership interest in the property. Revenues and expenses for such services are eliminated in our statement of operations, with
any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are
issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of
$22.1 million, $89.5 million, and $64.3 million for 2015, 2014, and 2013, respectively from our contract drilling segment and
eliminated the associated operating expense of $18.3 million, $62.4 million, and $46.9 million during 2015, 2014, and 2013,
respectively, yielding $3.8 million, $27.1 million, and $17.4 million during 2015, 2014, and 2013, respectively, as a reduction
to the carrying value of our oil and natural gas properties.

Gas Gathering and Processing Revenue. Our gathering and processing segment recognizes revenue from the gathering

and processing of natural gas and NGLs in the period the service is provided based on contractual terms.

Insurance. We are self-insured for certain losses relating to workers’ compensation, control of well and employee
medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from zero to
$1.0 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate
exposure to certain types of claims. However, there is no assurance that the insurance coverages we have will adequately
protect us against liability from all potential consequences. Unit Texas Drilling, L.L.C. was merged into its parent company,
Unit Drilling Company, effective October 31, 2015, at which time the ERISA governed occupational injury benefit program
was closed. All new claims after this date are processed under an existing insured workers’ compensation program. If insurance
coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles, or any combination
of these rather than pay higher premiums.

Derivative Activities. All derivatives are recognized on the balance sheet and measured at fair value. For our economic

hedges that we did not apply cash flow accounting to, any changes in their fair value occurring before their maturity (i.e.,
temporary fluctuations in value) are reported in gain (loss) on derivatives not designated as hedges and hedge ineffectiveness,
net in our Consolidated Statements of Operations. The commodity derivative instruments we had under cash flow accounting
expired as of December 2013. Previous changes in the fair value of derivatives designated as cash flow hedges, to the extent
they were effective in offsetting cash flows attributable to the hedged risk, were recorded in OCI until the hedged item was
recognized into earnings. When the hedged item was recognized into earnings, it was reported in oil and natural gas revenues.
Any change in fair value resulting from ineffectiveness was recognized in gain (loss) on derivatives not designated as hedges
and hedge ineffectiveness, net. In August 2012, we determined on a prospective basis, to enter into economic hedges without
electing cash flow hedge accounting.

We do not engage in derivative transactions for speculative purposes. We document our risk management strategy, and for

the cash flow hedges, we tested the hedge effectiveness at the inception of and during the term of each hedge.

Limited Partnerships. Unit Petroleum Company is a general partner in 15 oil and natural gas limited partnerships sold

privately and publicly. Some of our officers, directors, and employees own the interests in most of these partnerships. We share
in each partnership’s revenues and costs in accordance with formulas set out in each of the limited partnership agreement. The
partnerships also reimburse us for certain administrative costs incurred on behalf of the partnerships.

Income Taxes. Measurement of current and deferred income tax liabilities and assets is based on provisions of enacted

tax law; the effects of future changes in tax laws or rates are not included in the measurement. Valuation allowances are
established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax
payable for the year and the change during that year in deferred tax assets and liabilities.

The accounting for uncertainty in income taxes prescribes a recognition threshold and measurement attribute for the

financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also
provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We
have $0.4 million of unrecognized tax benefits.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Natural Gas Balancing. We use the sales method for recording natural gas sales. This method allows for recognition of

revenue, which may be more or less than its share of pro-rata production from certain wells. We estimate our December 31,
2015 balancing position to be approximately 4.7 Bcf on under-produced properties and approximately 4.8 Bcf on over-
produced properties. We have recorded a receivable of $2.5 million on certain wells where we estimate that insufficient reserves
are available for us to recover the under-production from future production volumes. We have also recorded a liability of $5.0
million on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to
recover their under-production from future production volumes. Our policy is to expense the pro-rata share of lease operating
costs from all wells as incurred. Such expenses relating to the balancing position on wells in which we have imbalances are not
material.

Employee and Director Stock Based Compensation. We recognize in our financial statements the cost of employee
services received in exchange for awards of equity instruments based on the grant date fair value of those awards. The amount
of our equity compensation cost relating to employees directly involved in exploration activities of our oil and natural gas
segment is capitalized to our oil and natural gas properties. Amounts not capitalized to our oil and natural gas properties are
recognized in general and administrative expense and operating costs of our business segments. We utilize the Black-Scholes
option pricing model to measure the fair value of stock options and stock appreciation rights (SARs). The value of our restricted
stock grants is based on the closing stock price on the date of the grants.

Impact of Financial Accounting Pronouncements.

Revenue from Contracts with Customers. The FASB has issued ASU 2014-09. This affects any entity using U.S. GAAP

NOTE 3 – DIVESTITURES

Oil and Natural Gas

In August 2013, we sold additional Bakken property interests. The proceeds, net of related expenses, were $57.1 million.
In addition, we had other non-core asset sales with proceeds, net of related expenses, of $21.7 million, $33.1 million, and $1.9
million in 2013, 2014, and 2015, respectively. Proceeds from these dispositions reduced the net book value of the full cost pool
with no gain or loss recognized.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Contract Drilling

During 2013, we sold five 2,000-3,000 horsepower drilling rigs to unaffiliated third-parties for a gain of $16.5 million.

Four of our idle drilling rigs were classified as assets held for sale at December 31, 2013.

These four drilling rigs were sold to an unaffiliated third party in the first quarter of 2014. The proceeds of this sale, less

costs to sell, exceeded the $16.3 million net book value of the drilling rigs, both in the aggregate and for each drilling rig,
resulting in a gain of $9.6 million.

During the first quarter of 2015, we sold one drilling rig to an unaffiliated third party for $0.3 million resulting in a gain

of $7,900. During the third quarter, we sold 30 drilling rigs, some old top drive equipment, and drill pipe in an auction. The
proceeds from the sale of those assets, less costs to sell, was less than the $11.0 million net book value resulting in a loss of
$7.3 million pre-tax.

NOTE 4 – EARNINGS (LOSS) PER SHARE

The following data shows the amounts used in computing earnings (loss) per share:

Income (Loss)
(Numerator)

Weighted
Shares
(Denominator)
(In thousands except per share amounts)

Per-Share
Amount

For the year ended December 31, 2013:

Basic earnings per common share .......................................................... $
Effect of dilutive stock options, restricted stock, and SARs ..................
Diluted earnings per common share ....................................................... $

For the year ended December 31, 2014:

For the year ended December 31, 2015:

184,746

—

184,746

136,276

—

136,276

Basic earnings (loss) per common share ................................................ $
Effect of dilutive stock options, restricted stock, and SARs ..................
Diluted earnings (loss) per common share ............................................. $

(1,037,361)
—
(1,037,361)

48,218

354

48,572

48,611

472

49,083

49,110

—

49,110

3.83
(0.03)
3.80

2.80
(0.02)
2.78

(21.12)
—
(21.12)

Due to the net loss for the year ended December 31, 2015, approximately 186,000 weighted average shares related to
stock options, restricted stock, and SARs were antidilutive and were excluded from the earnings per share calculation above.

The following options and their average exercise prices were not included in the computation of diluted earnings per

share because the option exercise prices were greater than the average market price of our common stock for the years ended
December 31:

Options and SARs..........................................................................................
Average exercise price................................................................................... $

261,270

73,500

50.34

64.43

149,665

58.41

2015

2014

2013

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 5 – ACCRUED LIABILITIES

Accrued liabilities consisted of the following as of December 31:

Lease operating expenses ..........................................................................................................

17,220

Employee costs..........................................................................................................................

Interest payable..........................................................................................................................

Taxes..........................................................................................................................................

Third-party credits .....................................................................................................................

Other ..........................................................................................................................................

12,641

6,321

3,767

3,326

3,643

20,709

31,451

6,654

3,284

2,825

5,248

Total accrued liabilities..............................................................................................................

46,918

70,171

2015

2014

(In thousands)

NOTE 6 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES

Long-Term Debt

Long-term debt consisted of the following as of December 31:

2015

2014

(In thousands)

Credit agreement with an average interest rates of 2.6% and 2.9% at December 31, 2015

and 2014, respectively ...........................................................................................................

6.625% senior subordinated notes due 2021, net of unamortized discount of $3.3 million

and $3.8 million at December 31, 2015 and 2014, respectively............................................

Total long-term debt ..................................................................................................................

281,000

166,000

646,662

927,662

646,163

812,163

Credit Agreement. On April 10, 2015, we amended our Senior Credit Agreement (credit agreement) to extend the maturity

date from September 13, 2016 to April 10, 2020. The amount we can borrow is the lesser of the amount we elect (from time to
time) as the commitment amount or the value of the borrowing base as determined by the lenders, but in either event not to
exceed the maximum credit agreement amount of $900.0 million. Our current commitment amount is $500.0 million. Our
current borrowing base is $550.0 million. We are charged a commitment fee ranging from 0.375% to 0.50% on the amount
available but not borrowed. The fee varies based on the amount borrowed as a percentage of the amount of the total borrowing
base. To date, for this new amendment, we paid $2.6 million in origination, agency, syndication, and other related fees. We are
amortizing these fees over the life of the credit agreement.

The amount of the borrowing base–which is subject to redetermination by the lenders on April 1st and October 1st of

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered

Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50%
depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days,
whichever is less. Borrowings not under LIBOR bear interest at the prime rate specified in the credit agreement that in any
event cannot be less than LIBOR plus 1.00%. Interest is payable at the end of each month and the principal may be repaid in
whole or in part at anytime, without a premium or penalty. At December 31, 2015, we had $281.0 million outstanding
borrowings under our credit agreement.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The credit agreement prohibits, among other things:

•

the payment of dividends (other than stock dividends) during any fiscal year in excess of 30% of our consolidated net
income for the preceding fiscal year;

the incurrence of additional debt with certain limited exceptions; and

the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our
properties, except in favor of our lenders.

The credit agreement also requires that we have at the end of each quarter:

•

a current ratio (as defined in the credit agreement) of not less than 1 to 1; and

a leverage ratio of funded debt to consolidated EBITDA (as defined in the credit agreement) for the most recently
ended rolling four fiscal quarters of no greater than 4 to 1.

As of December 31, 2015, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes. We have an aggregate principal amount of $650.0 million, 6.625% senior

The Notes are subject to an Indenture dated as of May 18, 2011, between us and Wilmington Trust, National Association

Unit, as the parent company, has no independent assets or operations. The guarantees by the Guarantors of the Notes

At any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Other Long-Term Liabilities

Other long-term liabilities consisted of the following as of December 31:

2015

2014

(In thousands)

ARO liability .............................................................................................................................

98,297

100,567

Capital lease obligations............................................................................................................

Workers’ compensation.............................................................................................................

Separation benefit plans ............................................................................................................

Gas balancing liability...............................................................................................................

Deferred compensation plan......................................................................................................

Other ..........................................................................................................................................

Less current portion...................................................................................................................

Total other long-term liabilities.................................................................................................

22,466

16,551

9,886

5,047

4,244

410

156,901

16,560
140,341

25,876

17,997

11,276

3,623

4,055

410

163,804

15,019
148,785

Estimated annual principal payments under the terms of debt and other long-term liabilities from 2016 through 2020 are

$16.6 million, $5.7 million, $59.9 million, $9.5 million, and $290.0 million, respectively.

Capital Leases

During 2014, our mid-stream segment entered into capital lease agreements for twenty compressors with initial terms of
seven years. The underlying assets are included in gas gathering and processing equipment. The current portion of our capital
lease obligations of $3.5 million is included in current portion of other long-term liabilities and the non-current portion of $18.9
million is included in other long-term liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2015.
These capital leases are discounted using annual rates of 4.0%. Total maintenance and interest remaining related to these leases
are $9.4 million and $2.7 million, respectively at December 31, 2015. Annual payments, net of maintenance and interest,
average $4.0 million annually through 2021. At the end of the term, our mid-stream segment has the option to purchase the
assets at 10% of the fair market value of the assets at that time.

Future payments required under the capital leases at December 31, 2015 are as follows:

Ending December 31,

2016 ....................................................................................................................................................................
2017 ....................................................................................................................................................................
2018 ....................................................................................................................................................................
2019 ....................................................................................................................................................................
2020 ....................................................................................................................................................................
2021 ....................................................................................................................................................................
Total future payments..................................................................................................................................

Less payments related to:

Maintenance........................................................................................................................................................
Interest ................................................................................................................................................................
Present value of future minimum payments .................................................................................

Amount

(In thousands)
6,168
$

6,168

3,769

34,609

9,445

2,698

22,466

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

We are required to record the estimated fair value of the liabilities relating to the future retirement of our long-lived assets

(AROs). Our oil and natural gas wells are plugged and abandoned when the oil and natural gas reserves in those wells are

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

depleted or the wells are no longer able to produce. The plugging and abandonment liability for a well is recorded in the period
in which the obligation is incurred (at the time the well is drilled or acquired). None of our assets are restricted for purposes of
settling these AROs. All of our AROs relate to plugging costs associated with our oil and gas wells.

The following table shows certain information about our AROs for the periods indicated:

2015

2014

(In thousands)

ARO liability, January 1:...........................................................................................................

100,567

133,657

Accretion of discount ................................................................................................................

Liability incurred .......................................................................................................................

Liability settled..........................................................................................................................

Liability sold..............................................................................................................................
Revision of estimates (1).............................................................................................................
ARO liability, December 31:.....................................................................................................

Less current portion...................................................................................................................
Total long-term ARO liability ...................................................................................................

3,453

6,754
(2,893)
(421)
(9,163)
98,297

3,965
94,332

4,599

6,246
(4,490)
(1,206)
(38,239)
100,567

3,204
97,363

_________________________
(1) Plugging liability estimates were revised in both 2015 and 2014 for updates in the cost of services used to plug wells over the preceding year. We had

various upward and downward adjustments as well as changes in estimated timing of cash flows.

NOTE 8 – INCOME TAXES

A reconciliation of income tax expense (benefit), computed by applying the federal statutory rate to pre-tax income (loss)

to our effective income tax expense (benefit) is as follows:

Income tax expense (benefit) computed by applying the statutory rate ........ $
State income tax, net of federal benefit .........................................................

Statutory depletion and other .........................................................................

Income tax expense (benefit)..................................................................

(582,508) $
(45,768)
1,328
(626,948) $

2015

2014
(In thousands)
78,029

2013

105,514

6,131

2,503

8,290

2,919

86,663

116,723

For the periods indicated, the total provision for income taxes consisted of the following:

Current taxes:

Federal .................................................................................................... $
State ........................................................................................................

Deferred taxes:

Federal ....................................................................................................

State ........................................................................................................

Total provision.................................................................................

2015

2014
(In thousands)

2013

(20,612) $

8,594

15,845

(4)
(20,616)

(535,691)
(70,641)
(606,332)
(626,948) $

784

9,378

68,360

8,925

77,285

86,663

146

15,991

87,839

12,893

100,732

116,723

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred tax assets and liabilities are comprised of the following at December 31:

Deferred tax assets:

Allowance for losses and nondeductible accruals..............................................................
Net operating loss carryforward .........................................................................................
Alternative minimum tax and research and development tax credit carryforward ............

Deferred tax liability:

Depreciation, depletion, amortization, and impairment .....................................................
Net deferred tax liability .............................................................................................
Current deferred tax asset..........................................................................................................
Non-current—deferred tax liability...........................................................................................

2015

2014

(In thousands)

56,479
140,863
5,409
202,751

55,231
54,901
25,991
136,123

(464,295)
(261,544)
14,206
(275,750) $

(1,000,811)
(864,688)
11,527
(876,215)

Realization of the deferred tax assets are dependent on generating sufficient future taxable income. Although realization is

not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the
deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are
reduced. At December 31, 2015, we have federal net operating loss carryforwards of approximately $351.4 million which
expire from 2021 to 2035.

We file income tax returns in the U.S. federal jurisdiction and various states. We are no longer subject to U.S. federal or
state income tax examinations by tax authorities for years before 2012. During 2014, we recognized a tax benefit relating to a
research and development tax credit carryforward in conjunction with our BOSS drilling rig activities. Due to the nature and
subjectivity surrounding the research and development credit and historical challenges by the IRS against companies who claim
the credit, it is our belief that the full amount of the credit may not be eventually allowed by the IRS once we are no longer in
an AMT tax paying position. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

Balance at January 1: .....................................................................................
Additions based on tax positions related to current year ...............................
Additions for tax positions of prior years ......................................................
Reductions for tax positions of prior years ....................................................
Settlements.....................................................................................................
Balance at December 31: ...............................................................................

2015

2014

2013

(In thousands)
$

— $

410

—

410

—

410

—

At December 31, 2015 and 2014, there was $0.4 million of unrecognized tax benefits that if recognized would affect the

annual effective tax rate. We did not have any unrecognized tax benefits in 2013.

NOTE 9 – EMPLOYEE BENEFIT PLANS

Under our 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage

of their total compensation, up to a specified maximum, to the plan. We may match each employee’s contribution, up to a
specified maximum, in full or on a partial basis. We made discretionary contributions under the plan of 235,104, 120,333, and
111,995 shares of common stock and recognized expense of $6.2 million, $5.2 million, and $6.0 million in 2015, 2014, and
2013, respectively.

We provide a salary deferral plan (Deferral Plan) which allows participants to defer the recognition of salary for income

tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined
unforeseeable emergency hardships. The liability recorded under the Deferral Plan at December 31, 2015 and 2014 was $4.2
million and $4.1 million, respectively. We recognized payroll expense and recorded a liability at the time of deferral.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Effective January 1, 1997, we adopted a separation benefit plan (Separation Plan). The Separation Plan allows eligible

employees whose employment is involuntarily terminated or, in the case of an employee who has completed 20 years of
service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of
service completed up to a maximum of 104 weeks. To receive payments, the recipient must waive any claims against us in
exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior
Management (Senior Plan). The Senior Plan provides certain officers and key executives of Unit with benefits generally
equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the
selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (Special
Plan). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest
of a participant’s reaching the age of 65 or serving 20 years with the company.

On December 31, 2008, we amended all three Plans to be in compliance with Section 409A of the Internal Revenue Code

of 1986, as amended. The key amendments to the Plans address, among other things, when distributions may be made, the
timing of payments, and the circumstances under which employees become eligible to receive benefits. On December 8, 2015,
we amended the Plans to change the calculation for determining the payouts at the time of a Separation of Service under the
Plans. None of the amendments materially increase the benefits, grants or awards issuable under the Plans. We recognized
expense of $3.0 million, $2.7 million, and $2.4 million in 2015, 2014, and 2013, respectively, for benefits associated with
anticipated payments from these separation plans.

We have entered into key employee change of control contracts with three of our current executive officers. These

severance contracts have an initial three-year term that is automatically extended for one year on each anniversary, unless a
notice not to extend is given by us. If a change of control of the company, as defined in the contracts, occurs during the term of
the severance contract, then the contract becomes operative for a fixed three-year period. The severance contracts generally
provide that the executive’s terms and conditions for employment (including position, work location, compensation, and
benefits) will not be adversely changed during the three-year period after a change of control. If the executive’s employment is
terminated (other than for cause, death, or disability), the executive terminates for good reason during such three-year period, or
the executive terminates employment for any reason during the 30-day period following the first anniversary of the change of
control, and on certain terminations prior to a change of control or in connection with or in anticipation of a change of control,
the executive is generally entitled to receive, in addition to certain other benefits, any earned but unpaid compensation; up to
2.9 times the executive’s base salary plus annual bonus (based on historic annual bonus); and the company matching
contributions that would have been made had the executive continued to participate in the company’s 401(k) plan for up to an
additional three years.

The severance contract provides that the executive is entitled to receive a payment in an amount sufficient to make the
executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. As a condition to
receipt of these severance benefits, the executive must remain in the employ of the company prior to change of control and
render services commensurate with his position.

NOTE 10 – TRANSACTIONS WITH RELATED PARTIES

Unit Petroleum Company serves as the general partner of 15 oil and gas limited partnerships. Two investments by third

parties and 13 (the employee partnerships) 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. The non-employee partnerships were formed
in 1984 and two in 1986. Effective December 31, 2014, the 1984 partnership was dissolved. Employee partnerships were
formed for each year beginning with 1984 and ending with 2011.

The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in

1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in
2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partners under the
authority contained in the respective partnership agreements and did not involve any vote, consent or approval by the limited
partners. The employee partnerships have each had a set percentage (ranging from 1% to 15%) of our interest in most of the oil
and natural gas wells we drill or acquire for our own account during the particular year for which the partnership was formed.
The total interest the employees have in our oil and natural gas wells by participating in these partnerships does not exceed one
percent.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Amounts received in the years ended December 31, from both public and private Partnerships for which Unit is a general

partner are as follows:

Contract drilling .............................................................................................

Well supervision and other fees.....................................................................

General and administrative expense reimbursement .....................................

2015

2014
(In thousands)
4

— $

2013

423

435

470

Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These
costs are billed to related parties on the same basis as billings to unrelated parties for such services. General and administrative
reimbursements are both direct general and administrative expense incurred on the related party’s behalf and indirect expenses
allocated to the related parties. Such allocations are based on the related party’s level of activity and are considered by
management to be reasonable.

The Chairman of our Board, John Nikkel is a 25.8% owner of Rampart Holdings, Inc. which owns 100% of Toklan Oil

and Gas Company (Toklan), an oil and gas exploration and production company located in Tulsa, Oklahoma. Mr. Nikkel's son,
Robert Nikkel is Toklan's President, and he owns 20.0% of the company. In 2014, there were two wells drilled for Toklan, one
of which was completed in 2014 and one of which was completed in 2015 with no activity in 2013. Under its usual standard
dayrate contract terms available generally to all similarly-situated customers at that time and in the same general drilling area,
the Company recognized revenue from Toklan of approximately $0.5 million in 2015 and $1.5 million in 2014. During 2014,
we received payments of $1.1 million and had an accounts receivable balance of $0.4 million at December 31, 2014. During
2015, we received payments of $0.9 million with no accounts receivable balance at December 31, 2015. The Company also
paid royalties in 2014, in the ordinary course of business, of approximately $0.2 million to Toklan. There were no material
royalties to disclose for 2013 or 2015. Also in 2015, Toklan paid $0.5 million for the North Custer Gathering System, an
inactive (since 2009) gathering system owned by our mid-stream segment. We determined that the capital required to re-
activate that system would not provide adequate returns based on future cash flow potential. If the system had not been sold to
Toklan, it would have been included in a multi-system asset sales package in which little value would have been assigned to it.
Toklan operates the North Custer Gathering System under its affiliate, West Thomas Field Services, LLC (West Thomas), a
company in which Mr. John Nikkel holds an approximate 25.0% ownership interest and in which Mr. Robert Nikkel has an
ownership interest of approximately 20.0%. West Thomas entered into a gas purchase agreement with our exploration and
production segment in November of 2015. Payments from West Thomas under that contract amounted to $0.1 million for 2015
volumes purchased.

One of our directors, G. Bailey Peyton IV, also serves as Manager of Peyton Royalties, LP, a family-controlled limited
partnership that owns royalty rights in wells in the Texas and Oklahoma Panhandles. The Company in the ordinary course of
business, paid royalties or lease bonuses, primarily due to its status as successor in interest to prior transactions and as operator
of the wells involved and, in some cases, as lessee, with respect to certain wells in which Mr. Peyton, members of Mr. Peyton's
family, and Peyton Royalties, LP have an interest. Such payments totaled approximately $0.8 million, $1.3 million, and $1.4
million during 2015, 2014, and 2013, respectively.

Our Audit Committee and the board, in accordance with our related party transaction policy, have determined that these

arrangements are in the best interest of the Company.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 11 – STOCK-BASED COMPENSATION

For restricted stock awards, we had:

Recognized stock compensation expense ...................................................... $
Capitalized stock compensation cost for our oil and natural gas properties..

Tax benefit on stock based compensation......................................................

2015 (1)

2014
(In millions)

2013

15.3

17.4

3.5

5.8

3.7

6.7

16.1

3.5

6.2

_________________________
(1) Recognized stock compensation was reduced by $3.2 million, capitalized stock compensation cost for our oil and natural gas properties was reduced by

$0.2 million, and the tax benefit was reduced by $1.2 million for lower expected payouts related to the performance shares.

The remaining unrecognized compensation cost related to unvested awards at December 31, 2015 is approximately $13.8
million of which $2.4 million is anticipated to be capitalized. The weighted average period of time over which this cost will be
recognized is 0.7 of a year.

The Second Amended and Restated Unit Corporation Stock and Incentive Compensation Plan effective May 6, 2015 (the

amended plan) allows us to grant stock-based and cash-based compensation to our employees (including employees of
subsidiaries) as well as to non-employee directors. A total of 4,500,000 shares of the company's common stock is authorized for
issuance to eligible participants under the amended plan with 2.0 million shares being the maximum number of shares that can
be issued as “incentive stock options.” Awards under this plan may be granted in any one or a combination of the following:

•

incentive stock options under Section 422 of the Internal Revenue Code;

non-qualified stock options;

performance shares;

performance units;

restricted stock;

restricted stock units;

stock appreciation rights;

cash based awards; and

other stock-based awards.

This plan also contains various limits as to the amount of awards that can be given to an employee in any fiscal year. All
awards are generally subject to the minimum vesting periods, as determined by our Compensation Committee and included in
the award agreement.

Expected volatilities are based on the historical volatility of our stock. We use historical data to estimate option exercise

and termination rates within the model and aggregate groups that have similar historical exercise behavior for valuation
purposes. To date, we have not paid dividends on our stock. The risk free interest rate is computed from the United States
Treasury Strips rate using the term over which it is anticipated the grant will be exercised.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

SARs

Activity pertaining to SARs granted under the amended plan is as follows:

Number of
Shares

Weighted
Average
Price

Outstanding at January 1, 2013 .................................................................................................

145,901

46.59

Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

Outstanding at December 31, 2013 ...........................................................................................

Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

Outstanding at December 31, 2014 ...........................................................................................
Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

—

145,901

—
(14,131)
—

131,770
—

—

46.59

—

46.50

—

46.60
—

—

Outstanding at December 31, 2015 ...........................................................................................

131,770

46.60

There were no SARs granted or vested during 2015, 2014, or 2013.

Exercise Prices
$44.31.............................................................................................................
$51.76.............................................................................................................

Outstanding and Exercisable SARs at
December 31, 2015

Weighted
Average
Remaining
Contractual
Life
2.0 years

0.9 years

Weighted
Average
Exercise Price
$44.31

$51.76

Number
of Shares
91,255

40,515

There were no SARs exercised in 2015. The SARs expire after 10 years from the date of the grant. There was no

aggregate intrinsic value on the 131,770 shares outstanding at December 31, 2015. The remaining weighted average contractual
term is 1.6 years.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Restricted Stock

Activity pertaining to restricted stock awards granted under the amended plan is as follows:

Employees
Nonvested at January 1, 2013 ............................................

Granted........................................................................

Vested..........................................................................

Forfeited ......................................................................

Nonvested at December 31, 2013 ......................................

Granted........................................................................

Vested..........................................................................

Forfeited ......................................................................

Nonvested at December 31, 2014 ......................................
Granted........................................................................

Vested..........................................................................

Forfeited ......................................................................

Nonvested at December 31, 2015 ......................................

Number of
Time Vested
Shares

523,024

396,144
(248,003)
(18,330)
652,835

383,448
(291,712)
(19,805)
724,766
576,361
(343,657)
(20,808)
936,662

Number of
Performance
Vested Shares
66,503

57,405

—

123,908

71,674
(13,092)
(6,970)
175,520
148,081
(39,245)
(7,196)
277,160

Total
Number of
Shares

Weighted
Average
Price

589,527

453,549
(248,003)
(18,330)
776,743

455,122
(304,804)
(26,775)
900,286
724,442
(382,902)
(28,004)
1,213,822

48.11

48.20

46.46

47.85

48.70

53.72

49.68

51.92

50.81
34.06

49.69

45.33

41.29

Non-Employee Directors
Nonvested at January 1, 2013....................................................................................................

Granted ...............................................................................................................................

Vested.................................................................................................................................

Forfeited .............................................................................................................................

Nonvested at December 31, 2013..............................................................................................

Granted ...............................................................................................................................

Vested.................................................................................................................................

Forfeited .............................................................................................................................

Nonvested at December 31, 2014..............................................................................................
Granted ...............................................................................................................................

Vested.................................................................................................................................

Forfeited .............................................................................................................................

Number of
Shares

Weighted
Average
Price

24,606

21,128
(10,030)
—

35,704

13,768
(14,336)
—

35,136
25,848
(18,920)
—

40.23

41.65

40.23

—

41.07

63.91

40.93

—

50.08
34.04

46.51

—

41.83

Nonvested at December 31, 2015..............................................................................................

42,064

The time vested restricted stock awards granted are being recognized over a three year vesting period. The performance
vested restricted stock awards, granted to certain executive officers, will cliff vest three years from the grant date based on the
company's achievement of certain stock performance measures at the end of the term and will range from 0% to 150% of the
restricted shares granted as performance shares. Based on a probability assessment of the selected performance criteria at
December 31, 2015, the participants are estimated to receive 2% of the 2015, 57% of the 2014, and 10% of the 2013
performance based shares.

The fair value of the restricted stock granted in 2015, 2014, and 2013 at the grant date was $24.5 million, $24.1 million,
and $21.3 million, respectively. The aggregate intrinsic value of the 401,822 shares of restricted stock that vested in 2015 on
their vesting date was $11.2 million. The aggregate intrinsic value of the 1,255,886 shares of restricted stock outstanding
subject to vesting at December 31, 2015 was $15.3 million with a weighted average remaining life of 0.7 of a year.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Employee Stock Option Plan

The Stock Option Plan, provided the granting of options for up to 2,700,000 shares of common stock to officers and
employees. The option plan permitted the issuance of qualified or nonqualified stock options. Options granted typically became
exercisable at the rate of 20% per year one year after being granted and expire after 10 years from the original grant date. The
exercise price for options granted under this plan was the fair market value of the common stock on the date of the grant. In
2006, as a result of the approval of the adoption of the Unit Corporation Stock and Incentive Compensation Plan, no further
awards were made under this plan. During 2015, the remaining options expired.

Activity pertaining to the Stock Option Plan is as follows:

Number of
Shares

Weighted
Average
Exercise
Price

Outstanding at January 1, 2013 .................................................................................................

118,030

Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

Outstanding at December 31, 2013 ...........................................................................................

Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

Outstanding at December 31, 2014 ...........................................................................................

Granted ...............................................................................................................................

Exercised ............................................................................................................................

Forfeited .............................................................................................................................

—
(48,110)
(1,000)
68,920

—
(21,490)
(37,930)
9,500

—

—
(9,500)

Outstanding at December 31, 2015 ...........................................................................................

— $

33.03

—

26.09

37.83

37.81

—

37.83

37.69

—

37.69

—

There were no shares that vested in 2015, 2014, or 2013. There were no options exercised in 2015 and no options

outstanding or exercisable in this plan at December 31, 2015.

Non-Employee Directors' Stock Option Plan

Under the Unit Corporation 2000 Non-Employee Directors’ Stock Option Plan, on the first business day following each

annual meeting of shareholders, each person who was then a member of our Board of Directors and who was not then an
employee of the company or any of its subsidiaries was granted an option to purchase 3,500 shares of common stock. The
option price for each stock option was the fair market value of the common stock on the date the stock options were granted.
The term of each option is 10 years and cannot be increased and no stock options were to be exercised during the first six
months of its term except in case of death. On May 2, 2012, our stockholders approved the amended plan which succeeds this
plan, and no further awards were made under the non-employee director option plan.

UNIT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Activity pertaining to the Directors’ Plan is as follows:

Number of
Shares

Weighted
Average
Exercise
Price

Outstanding at January 1, 2013 .................................................................................................

192,500