10-K 1 unt-20131231x10k.htm 10-K UNT-2013.12.31-10K
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, 2013
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     
Commission file number: 1-9260
UNIT CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
73-1283193
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
 
 
7130 South Lewis, Suite 1000
Tulsa, Oklahoma
74136
(Address of principal executive offices)
(Zip Code)
(Registrant’s telephone number, including area code) (918) 493-7700
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, par value $.20 per share
NYSE
Rights to Purchase Series A Participating
Cumulative Preferred Stock
NYSE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [x]    No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes [ ]    No [x]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [x]    No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [x]    No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer    [x]
 
Accelerated filer    [ ]
 
Non-accelerated filer    [ ]
 
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, 2013, 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, 2013) held by non-affiliates was approximately $1,080,689,810 Determination of stock ownership by non-affiliates was made solely for the purpose of this requirement, and the registrant is not bound by these determinations for any other purpose.
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
Outstanding at February 14, 2014
Common Stock, $0.20 par value per share
49,232,860 shares
DOCUMENTS INCORPORATED BY REFERENCE
Document
Parts Into Which Incorporated
Portions of the registrant’s definitive proxy statement (the “Proxy Statement”) with respect to its annual meeting of shareholders scheduled to be held on May 7, 2014. The Proxy Statement shall be filed within 120 days after the end of the fiscal year to which this report relates.
Part III
Exhibit Index—See Page 119



FORM 10-K
UNIT CORPORATION

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



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

MMcfe – Million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.
Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.
NGLs – Natural gas liquids.
NGPL-TXOK – Natural Gas Pipeline Co. of America/Texok zone.
NYMEX – The New York Mercantile Exchange.
OPIS – Oil Price Information Service.
PEPL – Panhandle East Pipeline Co.
Play – A term applied by geologists and geophysicists identifying an area with potential oil and gas reserves.
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, 2013

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 and, as appropriate, one or more of Unit Corporation and 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 and its subsidiaries. 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 14, 2014:
 
Completed gross wells in which we own an interest
9,842

Number of drilling rigs we own
117

Number of natural gas treatment plants we own
3

Number of processing plants we own
15

Number of natural gas gathering systems we own
38




1


2013 SEGMENT OPERATIONS HIGHLIGHTS


Oil and Natural Gas
Attained net proved oil, NGLs, and natural gas reserves of 159.9 million barrels of oil equivalents (MMBoe), a 7% increase over 2012 reserves.
Increased net proved oil and NGLs reserves by 10% over 2012.
Total production of 16.7 MMBoe or an 18% increase over 2012.
Participated in the drilling of 149 wells.
Sold non-core assets with proceeds of $78.8 million for the year.

Contract Drilling
Sold five 2,000-3,000 horsepower electric drilling rigs to unaffiliated third-parties.
Launched our new drilling program to design and build new proprietary 1,500 horsepower AC electric drilling rigs, called the BOSS drilling rig. The first BOSS drilling rig is expected to be completed and put into service for our oil and natural gas segment during the first quarter of 2014.
Moved two rigs into the Permian Basin of West Texas.

Mid-Stream
Gas gathered increased from 250,290 Mcf per day in 2012 to 309,554 Mcf per day in 2013, a 24% increase.
Gas processed increased from 133,987 Mcf per day in 2012 to 140,584 Mcf per day in 2013, a 5% increase.
Added 155 miles of pipeline (approximately a 12% increase) and connected 150 new wells to our various gathering systems.
Completed construction of a new gathering and processing facility in south central Kansas, known as the Reno system, and the related installation of two gas processing plants which provide 25 MMcf per day total processing capacity.
Completed the installation of a 30 MMcf per day plant at our Bellmon facility increasing our total processing capacity to 55 MMcf per day.
Purchased a new 60 MMcf per day gas processing plant for our Bellmon system and began installation of this plant which was completed in February 2014.
Completed the installation and upgrade of the Dove Creek processing plant at our Perkins facility increasing our processing capacity by 8 MMcf per day.
Completed construction of a new gathering system in north-central Pennsylvania, known as the Brookfield system.
Increased the contract mix as a percent of volume for fee-based contracts to 62% in 2013 from 39% in 2012.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 17 of our Notes to Consolidated Financial Statements in Item 8 of this report for information with respect to each of our segment’s revenues, profits or losses, and total assets.



2


OIL AND NATURAL GAS

General.    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
West division
Western and Southern Texas, Colorado, Wyoming, Montana, North Dakota, New Mexico, Southern Louisiana, and Mississippi
East division
East Texas, Eastern Oklahoma, Pennsylvania, Arkansas, and Northern Louisiana
Central division
Western Oklahoma, Texas Panhandle and Kansas

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

The following table presents certain information regarding our oil and natural gas operations as of December 31, 2013:
 
Our Divisions/Area
Number
of
Gross
Wells
 
Number
of Net
Wells
 
Number
of Gross
Wells in
Process
 
Number
of Net
Wells in
Process
 
2013 Average
Net Daily Production
 
 
 
 
Natural
Gas
(Mcf)
 
Oil
(Bbls)
 
NGLs (Bbls)
West division
3,119

 
515.39

 
2

 
0.75

 
35,787

 
1,889

 
2,720

East division
1,484

 
475.59

 
5

 
0.03

 
25,755

 
45

 
66

Central division
5,238

 
1,840.83

 
14

 
9.63

 
93,956

 
7,273

 
7,937

Total
9,841

 
2,831.81

 
21

 
10.41

 
155,498

 
9,207

 
10,723


As of December 31, 2013, we did not have any significant water floods, pressure maintenance operations, or any other material operations 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 operated and completed eight gross wells in 2013 with an average working interest of 100% and a success rate of 88%. Five of the eight wells were completed in our “Gilly” Basal Wilcox field bringing the total number of wells completed in that field to ten at year end 2013. Production for 2013 increased 21% as compared to 2012. Our first horizontal Wilcox well was completed in the fourth quarter of 2013 at an initial daily rate of approximately 4.4 MMcf per day and 73 barrels of condensate per day from approximately 1,500 feet of Basal Wilcox lateral. There are currently two Unit rigs drilling in our Wilcox play with plans to add a third rig in the second half of the year, which should result in approximately 10 to 12 gross vertical wells and two to four horizontal wells at an approximate net cost of $112 million for 2014.

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.

Central division.    In our Mississippian play in south central Kansas, the average daily production for 2013 increased approximately 218% as compared to 2012. We had first sales on eight Mississippian wells during 2013 with an average 30 day IP rate of 222 Boe per day consisting of an average of approximately 53% oil, 11% NGLs, and 36% natural gas with a 100% average working interest. The last four wells completed in the fourth quarter of 2013 had a significantly higher liquids cut consisting of approximately 79% oil, 6% NGLs, and 15% natural gas with an average 30 day IP rate of approximately 231 Boe per day. Two potential enhancements we may make to wells drilled in the play during 2014 are drilling extended lateral wells and testing different fracture stimulation designs. We have leased approximately 143,000 net acres in the play and are currently running two Unit drilling rigs and expect to spend approximately $111 million in 2014.
 

3


In the Marmaton horizontal oil play in Beaver County, Oklahoma, we had first sales on 41 horizontal wells during 2013 with an average 30 day IP rate of 371 Boe per day with an approximate average working interest of 75%. The average daily production for 2013 increased approximately 25% as compared to 2012. A decision from the Oklahoma Legislature to allow drilling extended lateral wells in the play is anticipated by May 2014. Two additional potential horizontal targets in the play are scheduled to be tested in 2014. We have leases on approximately 119,000 net acres and have two Unit rigs drilling in the play with current plans to spend approximately $70 million.

In the Texas Panhandle District, which consists primarily of Granite Wash (GW) wells and to a lesser degree Cleveland wells, the average daily production for 2013 increased approximately 28% over 2012. We had first sales on 23 horizontal GW wells, having an average peak 30 day IP rate of 5.2 MMcfe per day and an average working interest of 85%. We also had first sales on three Cleveland wells with an average peak 30 day rate of 3.9 MMcfe per day at an average working interest of 80%. We recently completed drilling operations on three separate well pads located in different sections of the Buffalo Wallow GW field. Each pad has three wells resulting in nine total wells that will target five different GW sand intervals. Six of the wells have been fracture stimulated and the remaining three wells are scheduled to be fracture stimulated in the first quarter 2014. We plan to monitor production from these three pads for approximately 90 days prior to resuming pad drilling in the field. We plan to run three to five drilling Unit rigs in the GW play and one Unit rig in the Cleveland play for 2014 with plans to spend approximately $174 million.

Dispositions and Acquisitions.    There were no material dispositions during 2011. In September 2012, we sold our interest in certain Bakken properties (located in North Dakota). The proceeds, net of related expenses, were $226.6 million. In addition, we sold certain oil and natural gas assets located in Brazos and Madison Counties,Texas, for approximately $44.1 million. 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 for 2013. Proceeds from these dispositions reduced the net book value of the full cost pool with no gain or loss recognized.

On July 20, 2011, we acquired certain producing properties from an unaffiliated seller for approximately $12.3 million in cash, after post-closing adjustments, consisting of 30 operated wells and 59 non-operated well interests located in Beaver, Harper, and Ellis Counties, Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The acquisition also included in excess of 12,000 net acres held by production available for future development.

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash from an unaffiliated seller. Included in the acquisition were more than 500 wells located principally in the Oklahoma Arkoma Woodford and Hartshorne Coal plays along with other properties located throughout Oklahoma and Texas. The acquisition also included approximately 55,000 net acres of which 96% was held by production.

On September 17, 2012, we acquired certain oil and natural gas assets from Noble. After final closing adjustments, the acquisition included approximately 83,000 net acres primarily in the Granite Wash, Cleveland, and various other plays in western Oklahoma and the Texas Panhandle. The adjusted amount paid was $592.6 million.
As of the effective date of the Noble acquisition (April 1, 2012), the estimated proved reserves of the acquired properties were 44 MMBoe, The acquisition added approximately 24,000 net leasehold acres to our Granite Wash core area in the Texas Panhandle with significant potential including approximately 600 possible future horizontal drilling locations. The total acreage acquired in other plays in western Oklahoma and the Texas Panhandle was approximately 59,000 net acres and was characterized by high working interest and operatorship, 95% of which was held by production. We also received four gathering systems as part of the transaction, as well as other miscellaneous assets.


4


Well and Leasehold Data.    The following tables identify certain information regarding our oil and natural gas exploratory and development drilling operations:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells drilled:
 
 
 
 
 
 
 
 
 
 
 
Exploratory:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 
1

 
1.00

 

 

East division

 

 

 

 

 

Central division

 

 
1

 
1.00

 

 

Total oil

 

 
2

 
2.00

 

 

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
2

 
2.00

 
3

 
2.49

 
5

 
4.13

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total natural gas
2

 
2.00

 
3

 
2.49

 
5

 
4.13

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division

 

 
1

 
1.00

 
7

 
6.50

East division

 

 

 

 

 

Central division

 

 

 

 

 

Total dry

 

 
1

 
1.00

 
7

 
6.50

Total exploratory
2

 
2.00

 
6

 
5.49

 
12

 
10.63

Development:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
1

 
0.08

 
29

 
4.10

 
21

 
4.57

East division

 

 

 

 

 

Central division
93

 
51.33

 
71

 
34.04

 
56

 
32.81

Total oil
94

 
51.41

 
100

 
38.14

 
77

 
37.38

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
9

 
8.60

 
7

 
4.44

 
9

 
6.26

East division
1

 

 
2

 
0.76

 
9

 
4.65

Central division
37

 
26.00

 
55

 
30.45

 
44

 
18.32

Total natural gas
47

 
34.60

 
64

 
35.65

 
62

 
29.23

Dry:
 
 
 
 
 
 
 
 
 
 
 
West division
3

 
1.35

 
1

 
0.80

 
3

 
2.03

East division

 

 

 

 
1

 
1.00

Central division
3

 
1.78

 

 

 
5

 
2.15

Total dry
6

 
3.13

 
1

 
0.80

 
9

 
5.18

Total development
147

 
89.14

 
165

 
74.59

 
148

 
71.79

Total wells drilled
149

 
91.14

 
171

 
80.08

 
160

 
82.42


5


 
Year Ended December 31,
 
2013
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Wells producing or capable of producing:
 
 
 
 
 
 
 
 
 
 
 
Oil:
 
 
 
 
 
 
 
 
 
 
 
West division
2,058

 
170.49

 
2,076

 
178.43

 
2,074

 
183.50

East division
42

 
1.91

 
54

 
3.17

 
54

 
3.17

Central division
891

 
426.75

 
807

 
382.34

 
631

 
273.31

Total oil
2,991

 
599.15

 
2,937

 
563.94

 
2,759

 
459.98

Natural gas:
 
 
 
 
 
 
 
 
 
 
 
West division
1,004

 
326.79

 
1,109

 
330.19

 
1,182

 
335.90

East division
1,435

 
472.68

 
1,632

 
519.62

 
1,636

 
522.15

Central division
4,266

 
1,382.62

 
4,245

 
1,362.87

 
3,097

 
683.08

Total natural gas
6,705

 
2,182.09

 
6,986

 
2,212.68

 
5,915

 
1,541.13

Total
9,696

 
2,781.24

 
9,923

 
2,776.62

 
8,674

 
2,001.11


As of February 14, 2014, we are currently drilling or participating in 13 gross (9.66 net) wells started during 2014.

Cost incurred for development drilling includes $136.7 million, $123.4 million, and $111.4 million in 2013, 2012, and 2011, respectively, to develop booked proved undeveloped oil and natural gas reserves.

The following table summarizes our leasehold acreage at December 31, 2013:
 
 
Year Ended December 31, 2013
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net (1)
 
Gross
 
Net
West division
282,448

 
94,918

 
166,432

 
112,403

 
448,880

 
207,321

East division
225,054

 
87,908

 
57,707

 
17,811

 
282,761

 
105,719

Central division
857,022

 
334,472

 
300,560

 
236,567

 
1,157,582

 
571,039

Total
1,364,524

 
517,298

 
524,699

 
366,781

 
1,889,223

 
884,079

_________________________ 
(1)
Approximately 90% (West – 83%; East – 48%; and Central – 97%) of the net undeveloped acres are covered by leases that will expire in the years 2014—2016 unless drilling or production extends the terms of those leases. Currently, we do not have any material proved undeveloped (PUD) reserves attributable to acreage where the expiration date precedes the scheduled PUD reserve development plan.




6


Price and Production Data.    The following tables identify the average sales price, production volumes, and average production cost per equivalent barrel for our oil, NGLs, and natural gas production for the years indicated:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Average sales price per barrel of oil produced:
 
 
 
 
 
Price before hedging
$
95.18

 
$
90.19

 
$
93.49

Effect of hedging
(0.12
)
 
2.41

 
(6.31
)
Price including hedging
$
95.06

 
$
92.60

 
$
87.18

Average sales price per barrel of NGLs produced:
 
 
 
 
 
Price before hedging
$
31.79

 
$
30.70

 
$
44.44

Effect of hedging

 
0.88

 
(0.80
)
Price including hedging
$
31.79

 
$
31.58

 
$
43.64

Average sales price per Mcf of natural gas produced:
 
 
 
 
 
Price before hedging
$
3.33

 
$
2.53

 
$
3.78

Effect of hedging
(0.01
)
 
0.84

 
0.48

Price including hedging
$
3.32

 
$
3.37

 
$
4.26


7


 
Year Ended December 31,
 
2013
 
2012
 
2011
Oil production (MBbls):
 
 
 
 
 
West division
690

 
1,071

 
893

East division
16

 
16

 
12

Central division:
 
 
 
 
 
Mendota field
412

 
497

 
262

All other central division fields
2,242

 
1,695

 
1,344

Total central division
2,654

 
2,192

 
1,606

Total oil production (MBbls)
3,360

 
3,279

 
2,511

NGLs production (MBbls):
 
 
 
 
 
West division
993

 
858

 
798

East division
24

 
23

 
5

Central division:
 
 
 
 
 
Mendota field
1,050

 
1,128

 
691

All other central division fields
1,847

 
787

 
745

Total central division
2,897

 
1,915

 
1,436

Total NGLs production (MBbls)
3,914

 
2,796

 
2,239

Natural gas production (MMcf):
 
 
 
 
 
West division
13,062

 
11,831

 
11,774

East division
9,401

 
11,906

 
12,768

Central division:
 
 
 
 
 
Mendota field
9,138

 
8,957

 
4,887

All other central division fields
25,156

 
16,236

 
14,675

Total central division
34,294

 
25,193

 
19,562

Total natural gas production (MMcf)
56,757

 
48,930

 
44,104

Total production (MBoe):
 
 
 
 
 
West division
3,860

 
3,901

 
3,653

East division
1,607

 
2,023

 
2,145

Central division:
 
 
 
 
 
Mendota field
2,985

 
3,118

 
1,768

All other central division fields
8,282

 
5,188

 
4,535

Total central division
11,267

 
8,306

 
6,303

Total production (MBoe)
16,734

 
14,230

 
12,101

Average production cost per equivalent Bbl (1)
$
7.63

 
$
7.00

 
$
6.90

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

Our Mendota field, located in the Granite Wash play, includes 18%, 19%, and 22%, respectively of our total proved reserves in 2013, 2012, and 2011, respectively, expressed on an oil equivalent barrels basis, and is the only field that is greater than 15% of our proved reserves.


8


Oil, NGLs, and Natural Gas Reserves.    The following table identifies our estimated proved developed and undeveloped oil, NGLs, and natural gas reserves:
 
 
 
 
Oil
(MBbls)
 
NGLs (MBbls)
 
Natural
Gas
(MMcf)
 
Total
Proved
Reserves
(MBoe)
Proved developed:
 
 
 
 
 
 
 
West division
3,244

 
5,981

 
79,760

 
22,518

East division
38

 
28

 
97,891

 
16,381

Central division
12,312

 
24,428

 
286,583

 
84,504

Total proved developed
15,594

 
30,437

 
464,234

 
123,403

Proved undeveloped:
 
 
 
 
 
 
 
West division
325

 
599

 
8,121

 
2,278

East division

 

 
9,428

 
1,571

Central division
5,846

 
10,169

 
100,001

 
32,682

Total proved undeveloped
6,171

 
10,768

 
117,550

 
36,531

Total proved
21,765

 
41,205

 
581,784

 
159,934


Oil, NGLs, and natural gas reserves cannot be measured exactly. Estimates of oil, NGLs, and natural gas 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 for over seventy years. 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, 2013 and comprised 84% of the total proved developed discounted future net income and 91% of the total proved undeveloped discounted future net income (based on the unescalated pricing policy of the SEC).

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. Fred P. Richoux is the primary technical person in charge on behalf of Ryder Scott for their audit of our reserves.

Mr. Richoux, an employee of Ryder Scott since 1978, is the President and member of the Board of Directors at Ryder Scott. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide as well as other administrative functions at the Company. Before joining Ryder Scott, Mr. Richoux served in a number of engineering positions with Phillips Petroleum Company.

Mr. Richoux earned a Bachelor of Science degree in Electrical Engineering from the University of Louisiana at Lafayette and is a registered Professional Engineer in the State of Texas and the Province of Alberta. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.


9


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. Richoux fulfills.

Based on his educational background, professional training and more than 45 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Richoux has attained the professional qualifications as a Reserves Estimator (requires appropriate degree and/or is registered as Professional Engineer and has a minimum of 3 years experience in the estimation and evaluation of reserves) and Reserves Auditor (requires appropriate degree and/or is registered as Professional Engineer and has a minimum of 10 years experience in the estimation and evaluation of reserves of which at least 5 years of such experience is being in responsible charge of the estimation and evaluation of reserves) set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. For more information regarding Mr. Richoux’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.

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

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 Society of Petroleum Engineers (SPE) since 1991.

Mr. Lyon received a Bachelor of Science degree in Petroleum Engineering from the University of Tulsa in 1972 and has spent 34 of his 41 years in the industry directly involved in reserve calculation work. Included in this time were 15 years working for petroleum consulting firms Raymond F. Kravis and Associates and Southmayd and Associates performing independent reserve appraisals and audits for corporations and individuals. He joined Unit in 1996 and has shared responsibility for preparation of the company’s reserve report since that time. Mr. Lyon is a registered professional engineer in the State of Oklahoma and a member of the SPE.

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

10



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 is the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first day of 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, 2013, we had approximately 180 gross proved undeveloped wells all of which we plan to develop within five years of initial disclosure at a net estimated cost of approximately $508.3 million. The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United States for the years 2014—2017, as disclosed in our December 31, 2013 oil and natural gas reserve report, are $238.3 million, $185.4 million, $25.1 million, and $59.5 million, respectively. Our proved undeveloped reserves reported at December 31, 2013 did not include reserves that we did not expect to develop within five years of initial disclosure of those reserves. During 2013, we added new PUD reserves through extensions and discoveries representing 4.1 MMBls of oil, 5.0 MMBls of NGLs, and 52.7 Bcf of natural gas. We converted 47 proved undeveloped wells into proved developed wells at a cost of approximately $136.7 million. The proved undeveloped reserves that were converted to proved developed reserves during 2013, represented 1.8 MMBls of oil, 2.6 MMBls of NGLs, and 21.6 Bcf of natural gas. There were no other material changes to the PUD reserves.

Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2013, 2012, and 2011, 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 2013, sales to Valero Energy Corporation accounted for 25% of our oil and natural gas revenues. There was no other company that accounted for more than 10% of our oil and natural gas revenues. During 2013, our mid-stream segment purchased $83.0 million of our natural gas and NGLs production and provided gathering and transportation services of $8.0 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 2012 and 2011, we eliminated intercompany revenues of $73.3 million and $76.1 million, respectively, attributable to the intercompany purchase of our production of natural gas and NGLs as well as gathering and transportation services.


11


CONTRACT DRILLING

General.    Our contract drilling business is conducted through Unit Drilling Company and its subsidiary Unit Texas Drilling L.L.C. Through these companies 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, Colorado, Utah, Montana, and North Dakota.

The following table identifies certain information concerning our contract drilling operations:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Number of drilling rigs owned at year end
121.0

 
127.0

 
127.0

Average number of drilling rigs owned during year
125.4

 
127.4

 
123.7

Average number of drilling rigs utilized
65.0

 
73.9

 
76.1

Utilization rate (1)
52
%
 
58
%
 
61
%
Average revenue per day (2)
$
17,486

 
$
19,774

 
$
17,520

Total footage drilled (feet in 1,000’s)
10,578

 
10,551

 
9,749

Number of wells drilled
793

 
773

 
742

_________________________
(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 minus rental revenue from our contract drilling operations divided by the total number of days our drilling rigs were used minus the rental days 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, skidding systems, large air compressors, trucks, and other support equipment.

The maximum depth capacities of our various drilling rigs range from 5,000 to 40,000 feet. In 2013, 78 of our 121 drilling rigs were used in drilling services.

The following table shows certain information about our drilling rigs (including their distribution) as of February 14, 2014:

Divisions
Contracted
Rigs
 
Non-Contracted
Rigs
 
Total
Rigs
 
Average
Rated
Drilling
Depth
(ft)
Mid-Continent
23

 
6

 
29

 
17,879

Woodward
12

 
4

 
16

 
13,719

Panhandle
9

 
17

 
26

 
12,885

Gulf Coast
8

 
6

 
14

 
17,929

Rocky Mountain
15

 
17

 
32

 
17,188

Totals
67

 
50

 
117

 
16,017


Drilling rig utilization steadily increased throughout 2011 and through the first quarter of 2012. It began declining from the second quarter of 2012 and throughout the remainder of 2012 with utilization remaining relatively flat throughout 2013. Factors contributing to the fluctuating utilization include drilling efficiencies attained by operators, more acreage in certain

12


plays being held by production, and weakness in commodity prices. Our active drilling rig count at the start of 2011 was 72 drilling rigs. It decreased to 62 rigs at the end of 2012 and finished out 2013 at 65.

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 NGL production. During the last several years operators have focused their operations in this basin on the Cana Woodford, Granite Wash, Marmaton, and Mississippian horizontal plays. Three of our divisions work in this basin. During 2013, our Mid-Continent, Panhandle, and Woodward divisions averaged 22.0, 9.5, and 10.3 drilling rigs operating, respectively.

Gulf Coast – Our Gulf Coast division provides drilling rigs to the onshore areas of Louisiana, Texas Gulf Coast, East Texas, South Texas. Recently two drilling rigs were moved into the Permian Basin of West Texas. During 2013, this division averaged 6.7 drilling rigs operating. Within this division, our largest drilling rig, Rig 201, a 4,000 horsepower rig rated to drill to 40,000 feet, drilled an ultra-deep exploration well for a major oil company in south Louisiana, establishing the record for the deepest onshore well in the state of Louisiana. 

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 16.5 drilling rigs during 2013. We had six drilling rigs operating in the Pinedale Anticline of western Wyoming and ten drilling rigs operating in the Bakken Shale of North Dakota at the end of 2013.

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 increase with increased demand for our drilling rigs. Our average utilization rate for 2011, 2012, and 2013 was 61%, 58%, and 52%, respectively.

The following table shows the average number of our drilling rigs working by quarter for the years indicated:
 
 
2013
 
2012
 
2011
First quarter
66.3

 
81.5

 
70.0

Second quarter
65.2

 
76.7

 
73.1

Third quarter
63.5

 
73.4

 
78.9

Fourth quarter
65.0

 
64.0

 
82.1


Drilling Rig Fleet.    The following table summarizes the changes made to our drilling rig fleet in 2013. A more complete discussion of the changes follows the table:
 
Drilling rigs owned at December 31, 2012
127

Drilling rigs sold
(5
)
Drilling rigs removed from service
(1
)
Drilling rigs purchased

Drilling rigs constructed

Total drilling rigs owned at December 31, 2013
121


Dispositions, Acquisitions, and Construction.   During 2011, we were awarded two new build drilling rig contracts for 1,500 horsepower, diesel-electric drilling rigs. One was placed into service during the fourth quarter of 2011 and the other was placed in service during the first quarter of 2012, both in Wyoming.
During the first quarter of 2012, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third-party. In the second quarter we placed a new 1,500 horsepower, diesel-electric drilling rig to work in North Dakota under a three year contract.

13


During the third quarter of 2012, we had a fire on one of our drilling rigs located in the mid-continent region. The net book value of the damaged equipment was $3.2 million. All of the net book value of the damaged equipment was recovered from insurance proceeds. No personnel were injured in this incident.
In the second quarter of 2013, we sold one of our 2,000 horsepower electric drilling rigs. During the third and fourth quarters of 2013, we sold three additional 2,000 horsepower and one 3,000 horsepower electric drilling rigs. All of these sales were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party in the first quarter of 2014 all of which were classified as assets held for sale at December 31, 2013. The proceeds from these various sales will be used in our new drilling rig program we launched to design and build a new proprietary 1,500 horsepower, AC electric drilling rig, called the BOSS rig. We anticipate the BOSS drilling rig will position us to more effectively meet the demands of our existing customers as well as allowing us to compete for the work of new customers.

The first BOSS drilling rig will be operational the first quarter of 2014 and will work initially for our oil and natural gas segment. Two additional BOSS drilling rigs are contracted to third party operators and are anticipated to be placed into service in the second and third quarters of 2014.

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. Additional compensation may be acquired for special risks and unusual conditions. 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. We did not have any footage or turnkey contracts in 2013, 2012, or 2011.

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. All of our work during the last three years was under daywork contracts. 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 2013, QEP Resources, Inc. and Kodiak Oil and Gas Corp. were our largest drilling customers accounting for approximately 18% and 10%, respectively, of our total contract drilling revenues. Our work for these customers 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 2013, 2012, and 2011, our contract drilling segment drilled 105, 78, and 81 wells, respectively, or 13%, 10%, and 11%, respectively, of the total wells drilled for our oil and natural gas 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 income statement, 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 $64.3 million, $49.6 million, and $52.2 million during 2013, 2012, and 2011, respectively, from our contract drilling segment and eliminated the associated operating expense of $46.9 million, $34.1 million, and $32.6

14


million during 2013, 2012, and 2011, respectively, yielding $17.4 million, $15.5 million, and $19.6 million during 2013, 2012, and 2011, 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, 15 processing plants, 38 active gathering systems, and approximately 1,500 miles of pipeline. Superior and its subsidiaries operate in Oklahoma, Texas, Kansas, Pennsylvania, and West Virginia.

The following table presents certain information regarding our mid-stream segment for the years indicated:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
Gas gathered—Mcf/day
309,554

 
250,290

 
188,569

Gas processed—Mcf/day
140,584

 
133,987

 
92,940

NGLs sold—gallons/day
543,602

 
542,578

 
412,064


Dispositions and Acquisitions.    This segment did not have any significant dispositions or acquisitions during 2011 or 2013.

Included within the previously discussed acquisition of certain oil and natural gas assets from Noble were four gathering systems. These systems were transferred into our mid-stream segment. The cost for the systems was $18.7 million. Subsequently in 2013, one of these gathering systems was transferred to our oil and natural gas segment.

In December 2012, our mid-stream segment had a $1.2 million write down of its Erick system in conjunction with the shut down of this system.

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 and transporting raw natural gas. Our mid-stream’s revenue is a function of the volume of natural gas that is gathered or transported and is not directly dependent on the value of the natural gas. For the year ended December 31, 2013, 62% of our mid-stream segment’s total volumes and 37% of its operating margins (as defined below) were under fee-based contracts.
Percent of Proceeds Contracts (POP).    These contracts provide for our mid-stream segment to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers and processes, with the remainder being paid to the producer. In this arrangement, Superior and the producer each own a portion of the commodity and are directly dependent on the volume and value of the commodity both of which fluctuate. For the year ended December 31, 2013, 36% of our mid-stream segment’s total volumes and 59% of operating margins (as defined below) were under POP contracts.
Percent of Index Contracts (POI).    Under these contracts our mid-stream segment, as the processor, purchases raw well-head natural gas from the producer at a stipulated index price and, after processing the natural gas, sells the processed residual gas and the produced NGLs to third parties. Our mid-stream segment is subject to the economic risk (processing margin risk) that the aggregate proceeds from the sale of the processed natural gas and the NGLs could be less than the amount paid for the unprocessed natural gas. For the year ended December 31, 2013, 2% of our mid-stream segment’s total volumes and 4% of operating margins (as defined below) were under POI contracts.

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

Customers.    During 2013, ONEOK, Inc. and Tenaska Resources, LLC accounted for approximately 50% and 16%, respectively, of our mid-stream revenues. We believe that if we lost one or both of these identified customers, there are other

15


customers available to purchase our gas and NGLs. During 2013, 2012, and 2011 this segment purchased $83.0 million, $68.2 million, and $71.5 million, respectively, of our oil and natural gas segment's natural gas and NGLs production, and provided gathering and transportation services of $8.0 million, $5.1 million, and $4.6 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. Historically, 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 our hedging activity:
 
 
Oil Price per Bbl
 
NGLs Price per Bbl
 
Natural Gas Price per Mcf
Quarter
High
 
Low
 
High
 
Low
 
High
 
Low
2013
 
 
 
 
 
 
 
 
 
 
 
Fourth
$
97.34

 
$
91.15

 
$
36.33

 
$
31.92

 
$
3.36

 
$
3.08

Third
$
104.25

 
$
101.70

 
$
33.14

 
$
24.78

 
$
3.33

 
$
2.79

Second
$
92.85

 
$
89.97

 
$
32.17

 
$
28.94

 
$
4.04

 
$
3.73

First
$
93.89

 
$
90.80

 
$
37.97

 
$
33.14

 
$
3.20

 
$
3.04

2012
 
 
 
 
 
 
 
 
 
 
 
Fourth
$
87.01

 
$
84.39

 
$
34.82

 
$
32.42

 
$
3.57

 
$
2.54

Third
$
90.04

 
$
82.69

 
$
24.07

 
$
18.02

 
$
2.78

 
$
2.19

Second
$
100.63

 
$
76.35

 
$
34.65

 
$
24.65

 
$
2.34

 
$
1.65

First
$
104.32

 
$
97.31

 
$
39.77

 
$
36.04

 
$
2.80

 
$
2.17

2011
 
 
 
 
 
 
 
 
 
 
 
Fourth
$
97.26

 
$
86.63

 
$
46.16

 
$
40.57

 
$
3.46

 
$
3.16

Third
$
96.90

 
$
85.68

 
$
47.08

 
$
45.44

 
$
4.30

 
$
3.68

Second
$
107.87

 
$
95.78

 
$
49.43

 
$
44.60

 
$
4.04

 
$
3.83

First
$
99.77

 
$
86.14

 
$
41.66

 
$
38.35

 
$
4.11

 
$
3.53


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 to agree on prices and their ability to maintain production quotas;
actions taken by foreign oil and natural gas producing nations;
the price of foreign oil imports;
imports and exports of 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 natural gas;
weather conditions;
domestic and foreign government regulations;

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the price, availability, and acceptance of alternative fuels;
volatility in ethane prices causing rejection of ethane as part of the liquids processed stream; and
worldwide economic conditions.

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

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

Our mid-stream operations provide us greater flexibility in delivering our (and other 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 gasand 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.

It is possible that the current industry shift in drilling for oil and NGLs may at some point impact future natural gas availability as well as prices for natural gas. In addition, the increasing availability of oil and NGLs may impact the price for these products if supply was to exceed demand.

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 continued drilling 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 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 16 oil and natural gas limited partnerships. Three of these partnerships were formed in 1984 and 1986 for investment by third parties and 13 (the employee partnerships) were formed each year beginning with 1984 and ending with 2011 to allow our employees and directors the opportunity to participate with Unit Petroleum Company in its operations.

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.

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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 14, 2014, we had approximately 1,901 employees in our contract drilling segment, 351 employees in our oil and natural gas segment, 132 employees in our mid-stream segment, and 79 in our general corporate area. None of our employees are members of a union or labor organization nor have our operations ever been interrupted by a strike or work stoppage. We consider relations with our employees to be satisfactory.

GOVERNMENTAL REGULATIONS

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.

Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission (the FERC) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC’s jurisdiction over interstate natural gas sales has been substantially modified by the Natural Gas Policy Act under which the 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. The FERC’s jurisdiction over interstate natural gas transportation is not affected by the Decontrol Act.

Our sales of natural gas will be affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes are intended by the 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, the 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

18


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 the 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.

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, the 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, the FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced by the oil pipeline industry and make 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 the FERC will have on us.

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 those laws.

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.

19



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. For instance, the American Burying Beetle and the Lesser Prairie-Chicken both have habitat in some areas where we operate or provide services. The U.S. Fish and Wildlife Service (“FWS”) identified the Lesser Prairie-Chicken as candidate for listing in 1998 and initiated the process to list it as “threatened” or “endangered” in November 2012. Its habitat is found in Colorado, Kansas, New Mexico, Oklahoma and Texas, and it is listed as “threatened” by the State of Colorado. On December 17, 2013 the FWS stated that it would make a decision “on its final listing determination no later than March 30, 2014.” The sage grouse and certain wildflower species, among others, are also species that have been or are being considered for protected status under the ESA and whose range can coincide with oil and natural gas production activities. 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 Regulation.    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 likely will be finalized in 2014. 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.

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, has commenced a study of 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 is also 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. On November 20, 2013 the U.S. House of Representatives passed a bill, H.R. 2728, 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 it 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, 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, waste disposal, and well construction requirements on these operations, and possibly even restrict or ban hydraulic fracturing in certain circumstances.

20


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.

Further, after reviewing extensive comments and making a number of changes to its previously July 28, 2011 proposed rules, on April 17, 2012 the EPA issued its final rules that subject a wide range of oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs (with the NSPS and NESHAPS published in the Federal Register on August 16, 2012). The EPA revised the NSPS for volatile organic compounds (VOCs) from leaking components at onshore gas processing plants and the NSPS for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by existing standards, which will regulate VOC emissions from gas wells, centrifugal and reciprocating compressors, pneumatic controllers, and storage vessels over a certain size. The EPA also made revisions to the existing leak detection and repair requirements for the oil and gas production source category and the natural gas transmission source category and established action limits reflecting most achievable control for certain previously uncontrolled emission sources. There also are additional testing and related notification, record keeping and reporting requirements. These changes were effective October 15, 2012.

The EPA regulations also result in the first federal air standards for natural gas wells that are hydraulically fractured. Refractured gas wells that use the “green completions” will not be considered affected from a federal standpoint. Operators may choose to flare for now from refractured wells and phase in green completions by January 1, 2015, but any such refractured well will be considered an affected facility for permitting purposes.

The EPA will be designating nonattainment areas for ozone standards for outdoor quality. These areas will include those areas with significant oil and gas activities. Nonattainment areas will be required to submit state implementation plans in 2015 and to attain the standard by 2015 and 2018 for areas classified as “Marginal” and “Moderate,” respectively. Areas classified as “Serious” must attain by 2021. The federal NSPS constitute a federally required minimum level of control. States have the flexibility to put their own program in place or implement existing programs as long as they are at least as protective as the federal NSPS.

Consequently, while we have been in the process of assessing and implementing the new EPA requirements as required, at this time we do not know and cannot predict with any degree of certainty what areas the EPA will designate nonattainment and what classification will be applied nor what the states may implement for such nonattainment areas which may affect our business segments and use of hydraulic fracturing practices.

We do not know and cannot predict whether there will be any further proposed 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

Revenues from our Canadian operations during the last three fiscal years, as well as information relating to long-lived assets attributable to those operations are immaterial. We have no other international operations.


21


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; and
the number of wells our oil and natural gas segment plans to drill during the year.
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.

22



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.

Contract Drilling Customer Demand.    With the exception of the drilling we do for our own account, the demand for our contract drilling services depends entirely on the needs of third parties. Based on past history, these parties’ requirements are subject to a number of factors, independent of any subjective factors that directly impact the demand for our drilling rigs, including the availability of funds to carry out their drilling operations. For many of these parties, even if they have available funds, their decision to spend those funds is often based on the then current price for oil, NGLs, and natural gas. Other factors that affect our ability to work our drilling rigs are: the weather which, under certain circumstances, can delay or even cause the abandonment of a project by an operator; the competition we face in securing the award of drilling contracts; our lack of prior history in and recognition in a new market area; and the availability of labor to operate our drilling rigs.

Oil, NGLs, and Natural Gas Prices.    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 liquid natural gas and liquefied petroleum gas imports and exports; and
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.
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 2013 production, a $0.10 per Mcf change in what we receive for our natural gas production, without the effect of hedging, would result in a corresponding $448,000 per month ($5.4 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $268,000 per month ($3.2 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 hedging, would have a $310,000 per month ($3.7 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 hedging arrangements such as swaps and collars. To date, we have hedged part, but not all of our production which only provides price protection against declines in oil, NGLs, and natural gas prices on the production subject to our hedges, but not otherwise. Should market prices for the production we have hedged exceed the prices due under our hedges, our hedging arrangements then expose us to risk of financial loss and limit the benefit to us of those increases in market prices. During 2013, substantially all of our oil, NGLs, and natural gas volumes were sold at market responsive prices. To help manage our cash flow and capital expenditure requirements, we hedged approximately 90% and 65% of our 2013 average daily production for oil and natural gas, respectively. A more thorough discussion of our hedging 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

23


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 reasons, estimates of the economically recoverable quantities of oil, NGLs, and natural gas attributable to any particular group of properties, classifications of those oil, NGLs, and natural gas reserves based on risk of recovery, and estimates of the future net cash flows from oil, NGLs, and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil, NGLs, and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues, and expenditures with respect to our oil, NGLs, and natural gas reserves will likely vary from estimates and those variances may be material.
The information regarding discounted future net cash flows included in this report is not necessarily the current market value of the estimated oil, NGLs, and natural gas reserves attributable to our properties. The use of full cost accounting requires us to use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. Actual future prices and costs may be materially higher or lower. Actual future net cash flows are also affected, in part, by the following factors:
the amount and timing of oil, NGLs, and natural gas production;
supply and demand for oil, NGLs, and natural gas;
increases or decreases in consumption; and
changes in governmental regulations or taxation.

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

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

As a result of these ceiling test rules, during the quarters ending June 30, 2012 and December 31, 2012, we recorded a non-cash ceiling test write down 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. No ceiling test write down was necessary during 2011 or 2013.
If there are declines in the 12-month average prices, we may be required to record a write-down in future periods.

We are continually identifying and evaluating opportunities to acquire oil and natural gas properties, including acquisitions that would be significantly larger than those we have consummated to date. 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.

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Debt and Bank Borrowing.    We have incurred and currently expect to continue to incur substantial capital expenditures because of the growth in our operations. Historically, we have funded our capital needs through a combination of internally generated cash flow and borrowings under our bank credit agreement. In 2011 and 2012, we issued $250.0 million (the 2011 Notes) and $400.0 million (the 2012 Notes), respectively, of senior subordinated notes (collectively, the Notes). We have also, from time to time, obtained funds through equity financing. We currently have, and will continue to have, a certain amount of indebtedness. At December 31, 2013, we had no outstanding long-term debt under our credit agreement and the amount of the Notes, net of unamortized discount, was $645.7 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 occur, 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, to a large extent, 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

There are many other factors that 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

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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 market disruptions may result in tight credit markets in the United States. Liquidity in the global-credit 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-market turmoil, we may not be able to obtain debt 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 rate of 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.

Prices for oil, NGLs, and natural gas are subject to wide fluctuations in response to relatively minor changes in the 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 Organization of Petroleum Exporting Countries to agree on prices and their ability to maintain production quotas;
the price of foreign oil imports;
imports and exports of liquefied natural gas;
actions of governmental authorities;
the domestic and foreign supply of oil, NGLs, and natural gas;
the level of consumer demand;
U.S. storage levels of oil, NGLs, and natural gas;
weather conditions;
domestic and foreign government regulations;
the price, availability, and acceptance of alternative fuels; 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

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volatile. Any decrease from current oil, NGLs, and natural gas prices would depress the level of exploration and production activity. This, in turn, would likely result in a decline 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.

Continued 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 continue to be available. Additionally, we are likely to continue to face intense competition from other companies for available acquisition opportunities.

There can be no assurance that we will:
be able to identify suitable acquisition opportunities;
have sufficient capital resources to complete additional acquisitions;
successfully integrate acquired operations and assets;
effectively manage the growth and increased size;
maintain the crews and market share to operate any future drilling rigs we may acquire; or
successfully improve our financial condition, results of operations, business or prospects in any material manner as a result of any completed acquisition.

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

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


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

We have experienced and may continue to experience substantial capital needs in the growth of our operations. We have $645.7 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 14, 2014, we had no 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,

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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.

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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 hedging 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 hedging arrangements. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil, NGLs, and natural gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices.

Estimates of our reserves are uncertain and may prove to be inaccurate.

There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs, and natural gas reserves depend on a number of variable factors, including historical production from the area compared with production from other producing areas, and assumptions concerning:
the effects of regulations by governmental agencies;
future oil, NGLs, and natural gas prices;
future operating costs;
severance and excise taxes;
development costs; and
workover and remedial costs.

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

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

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


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

We review quarterly the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC. Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10% per year. Application of the ceiling test generally requires pricing future revenue at the unweighted arithmetic average of the price on the first day of month for each month within the 12-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements, and requires a write-down for accounting purposes if the ceiling is exceeded. We may be required to write down the carrying value of our oil and natural gas properties when oil, NGLs, and natural gas prices are depressed. If a write-down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

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

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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.

Our shareholders’ rights plan and 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. We have also adopted a shareholders’ rights plan. Because of our shareholders’ rights plan and these 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

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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 2013 , QEP Resources, Inc. and Kodiak Oil and Gas Corp. were our largest drilling customers accounting for approximately 18% and 10%, respectively, of our total contract drilling revenues. No other third party customer accounted for 10% or more of our contract drilling revenues. Any of our customers may choose not to use our services and 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.

Shortages of completion equipment and services could delay or otherwise adversely affect our oil and natural gas segment’s operations.

In the past several years, the increase in horizontal drilling activity in certain areas has, at times, resulted in shortages in the availability of third party equipment and services required for the completion of wells drilled by our oil and natural gas segment. As a result, we have experienced delays in completing some of our wells. Although we have taken steps to try to reduce the delays associated with these services, we anticipate that these services will remain in high demand for the immediate future and could, at times, delay, restrict, or curtail part of our exploration and development operations, which could in turn harm our results.

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

We rely on certain natural gas producers for a significant portion of our natural gas and NGLs supply. While some of these producers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these producers, as a result of competition or otherwise, could have a material adverse effect on our mid-stream segment unless we were able to acquire comparable volumes from other sources.

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

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


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Reliance on management.

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

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

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

Derivatives regulation 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 derivatives regulation, 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, NGLs, 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 hedges 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 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 has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, 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, and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, 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

34


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 has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In addition, the U.S. Department of Energy is conducting 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 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.

Further, after reviewing extensive comments and making a number of changes to its previously July 28, 2011 proposed rules, on April 17, 2012 the EPA issued its final rules that subject a wide range of oil and gas operations (production, processing, transmission, storage, and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs (with the NSPS and NESHAPS published in the Federal Register on August 16, 2012). The EPA revised the NSPS for volatile organic compounds (VOCs) from leaking components at onshore gas processing plants and the NSPS for sulfur dioxide emissions from natural gas processing plants. The EPA also established standards for certain oil and gas operations not covered by existing standards, which will regulate VOC emissions from gas wells, centrifugal and reciprocating compressors, pneumatic controllers, and storage vessels over a certain size. The EPA also made revisions to the existing leak detection and repair requirements for the oil and gas production source category and the natural gas transmission source category and established action limits reflecting most achievable control for certain previously uncontrolled emission sources. There also are additional testing and related notification, record keeping and reporting requirements. These changes were effective October 15, 2012.

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.

On October 20, 2011, EPA announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs). The regulations will be developed under EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. EPA anticipates issuing the proposed rules in 2014.

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

35


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.

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, 2013, we had 180 proved undeveloped drilling locations. To the extent that we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves. The reclassification of those reserves could also have a negative effect on the borrowing base under our credit facility.

The cost of drilling, completing, and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, NGLs, and natural gas to be commercially viable after drilling, operating, and other costs.
The borrowing base under our credit agreement is determined semi-annually at the discretion of the lenders and is based in a large part on the prices for oil, NGLs, and natural gas.

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

Potential listing of species as “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions or delays on our operations and that of our customers, which could adversely affect our operations and financial results.
The federal Endangered Species Act, referred to as the “ESA,” and analogous state laws regulate a variety of activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators and service companies to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas. All three of our business segments could be subject to the effect of one or more species being listed as threatened or endangered within the areas of our operations. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future undertake operations. For instance, the American Burying Beetle and the Lesser Prairie-Chicken both have habitat in some areas where we operate or provide services. The FWS initiated the process to list the Lesser Prairie-

36


Chicken as threatened in November 2012, with a decision expected in March 2014. The sage grouse and certain wildflower species, among others, are also species that have been or are being considered for protected status under the ESA and whose range can coincide with oil and natural gas production activities. 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.

Our new drilling rig program to design and build new proprietary BOSS drilling rigs is subject to risks, including delays and cost overruns, and may not meet our expectations.

     We have launched a new drilling rig program to design and build new proprietary 1,500 horsepower AC electric drilling rigs, which we refer to as BOSS drilling rigs.  We anticipate that this new drilling rig will position us to more effectively meet the demands of our existing customers,  result in additional new-build contract opportunities and allow us to compete for the work of new customers.  The construction of 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 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 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 rig from our customer; and
failure or delay of third party equipment vendors or service providers.

As we design and build new BOSS drilling rigs, there can be no assurance that we will:

obtain additional new-build contract opportunities;
successfully integrate the new rigs with our existing drilling fleet;
successfully deploy the new rigs; or
successfully improve our financial condition, results of operations or prospects as a result of the new 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.


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Item 3.     Legal Proceedings
Panola Independent School District No. 4, et al. v. Unit Petroleum Company, No. CJ-07-215, District Court of Latimer County, Oklahoma.

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas drilling and spacing units for which the our exploration segment distributes royalty. The Plaintiffs' central allegation is that our 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 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 Oklahoma Supreme Court for certiorari and on October 8, 2012, the Plaintiff's petition was denied. The Plaintiffs filed a second request in 2013 to certify a class of royalty owners that is slightly smaller than their first attempt. We will continue to resist certification using the defenses described above, as well as new defenses based on the Court of Civil Appeals' decertification of the Plaintiffs' original class action. 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:

  
2013
 
2012
Quarter
High
 
Low
 
High
 
Low
First
$
49.68

 
$
43.75

 
$
50.82

 
$
41.53

Second
$
47.45

 
$
40.51

 
$
43.83

 
$
32.14

Third
$
47.49

 
$
42.50

 
$
46.27

 
$
34.59

Fourth
$
52.81

 
$
46.34

 
$
46.97

 
$
39.73


On February 14, 2014, the closing sale price of our common stock, as reported by the NYSE, was $52.57 per share. On that date, there were approximately 870 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.




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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.



39


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 2013, 2012, and 2011 activity.
 
 
As of and for the Year Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In thousands except per share amounts)
 
Revenues(1)
$
1,351,850

 
$
1,315,123

 
$
1,207,503

  
$
870,671

  
$
707,188

 
Net income (loss)
$
184,746

 
$
23,176

(2) 
$
195,867

 
$
146,484

 
$
(55,500
)
(3) 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
 
Basic
$
3.83

 
$
0.48

 
$
4.11

 
$
3.10

  
$
(1.18
)
 
Diluted
$
3.80

 
$
0.48

 
$
4.08

 
$
3.09

  
$
(1.18
)
 
Total assets
$
4,022,390

 
$
3,761,120

 
$
3,256,720

  
$
2,669,240

  
$
2,228,399

 
Long-term debt (4)
$
645,696

 
$
716,359

 
$
300,000

  
$
163,000

  
$
30,000

 
Other long-term liabilities
$
158,331

 
$
167,545

 
$
113,830

  
$
92,389

  
$
81,126

 
Cash dividends per common share
$

 
$

 
$

  
$

  
$

 
_________________________ 
(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)
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.
(3)
In March 2009, we incurred a non-cash ceiling test write down of our oil and natural gas properties of $281.2 million pre-tax ($175.1 million net of tax) due to low commodity prices at quarter-end.
(4)
Long-term debt is net of unamortized discount.


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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 and its subsidiaries. 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

Our current 2014 capital budget for all of our business segments forecasts a 33% increase over our 2013 capital expenditures, excluding acquisitions. Our oil and natural gas segment’s capital budget is $718.0 million, a 31% increase over 2013, excluding acquisitions and ARO liability. Our drilling segment’s capital budget is $132.0 million, a 105% increase over 2013. Our plans for 2014 include focusing on our new drilling rig program, a program we launched to design and build a new proprietary 1,500 horsepower AC electric drilling rig, called the BOSS rig. We also plan to refurbish and upgrade several of our existing drilling rigs in order that those drilling rigs can be used in horizontal drilling operations. Our mid-stream segment’s capital budget is $78.0 million, a 19% decrease from 2013, excluding acquisitions. New and continued projects are discussed further in the Executive Summary.

Our 2014 current capital expenditures budget is based on realized prices for the year of $90.08 per barrel of oil, $29.45 per barrel of NGLs, and $3.77 per Mcf of natural gas. This 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 internally generated cash flow and, if necessary, borrowings under our credit agreement.

As discussed in other parts of this report, the success of our consolidated business, as well as that of each of our three operating segments depends, to a large extent, on: the prices we receive for our oil, NGLs, and natural gas production; the demand for oil, NGLs, and natural gas; and the demand for our drilling rigs which, in turn, influences the amounts we can charge for the use of those drilling rigs. Although all of our current operations (with the exception of a minor amount of production in Canada) are located within the United States, events outside the United States can and do have an impact on us and our industry.

In addition to their direct impact on us, low commodity prices–if sustained for a long period of time–could impact the liquidity of some of our industry partners and customers which, in turn, could limit their ability to meet their financial obligations to us.

Executive Summary

Oil and Natural Gas

Fourth quarter 2013 production from our oil and natural gas segment was 4,438,000 barrels of oil equivalent (Boe), a 5% increase over the third quarter of 2013 and an 8% increase over the fourth quarter of 2012. These increases came primarily from production associated with new wells. Oil and NGLs production during the fourth quarter of 2013 was 46% of our total production compared to 41% of our total production during the fourth quarter of 2012.

Fourth quarter 2013 oil and natural gas revenues increased 11% over the third quarter of 2013 and increased 5% over the fourth quarter of 2012. These increases were primarily due to increases in production.


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Our NGLs and natural gas prices for the fourth quarter of 2013 increased 21% and 3%, respectively, over the third quarter of 2013 while our oil prices decreased 1%. Our oil prices increased 3% over the fourth quarter of 2012 while NGLs prices were essentially unchanged and natural gas prices decreased 12%.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) increased 20% over the third quarter of 2013 and 6% over the fourth quarter of 2012. The increases were primarily attributable to increased production from developmental drilling and acquisitions.

Operating cost per Boe produced for the fourth quarter of 2013 decreased 13% from the third quarter of 2013 and decreased 6% from the fourth quarter of 2012. The decrease from the third quarter of 2013 was primarily due to decreased lease operating expenses (LOE) due to decreased workover expense and lower gross production tax resulting from credits received. These decreases were somewhat offset by higher saltwater disposal expenses. The decrease from the fourth quarter of 2012 was primarily due to a decrease in well servicing and transportation charges and a decrease in production taxes due to tax credits.

For 2013 we hedged approximately 90% of our average daily oil production and approximately 65% of our average natural gas production to help manage our cash flow and capital expenditure requirements.

Currently for 2014 we have hedged approximately 7,250 Bbls per day of oil production and 90,000 Mmbtu per day of natural gas production. The oil production is hedged by swap contracts for 3,250 Bbls per day and collars for 4,000 Bbls per day. The swap transactions were done at a comparable average NYMEX prices of $92.35. The collar transactions were done at a comparable average NYMEX floor price of $90.00 and ceiling price of $96.08. The natural gas production is hedged by swaps for 80,000 Mmbtu per day and a collar for 10,000 Mmbtu per day. The swap transactions were done at a comparable average NYMEX price of $4.24. The collar transaction was done at a comparable average NYMEX floor price of $3.75 and ceiling price of $4.37. Additionally, we have hedged our March 2014 natural gas basis exposure with basis swaps at an average price of -$0.05.
In August 2013, we sold some of our Bakken oil and gas properties. 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.

During 2013, we drilled 149 wells (91.14 net wells). For 2014, we plan to participate in the drilling of approximately 180 wells. Our 2014 production guidance is approximately 19.2 to 19.7 MMBoe, an increase of 15% to 18% over 2013, although actual results will continue to be subject to many factors. This segment’s capital budget for 2014 is $718.0 million, a 31% increase over 2013, excluding acquisitions and ARO liability.

Contract Drilling

The rate at which our drilling rigs were used (“our utilization rate”) for the fourth quarter 2013 was 53%, compared to 51% and 50% for the third quarter of 2013 and the fourth quarter of 2012, respectively.

Dayrates for the fourth quarter of 2013 averaged $19,630, a 1% decrease from both the third quarter of 2013 and the fourth quarter of 2012. The decreases were primarily due to the expiration of certain contracts during 2013 that had higher rates.

Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2013 increased 3% over the third quarter of 2013 and was essentially unchanged from the fourth quarter of 2012. For both comparative periods utilization slightly increased.

Operating cost per day for the fourth quarter of 2013 decreased 3% from the third quarter of 2013 and 13% from the fourth quarter of 2012. The decreases were primarily due to decreases in direct rig expenses and workers' compensation related costs.
Today, almost all of our working drilling rigs are drilling horizontal or directional wells for oil and NGLs. Part of this shift included operators moving to shallower oil plays like the Mississippian play in northern Oklahoma and southern Kansas. These shallower plays tend to use drilling rigs with lower horsepower which have lower dayrates and margins.  As methods for drilling horizontal wells have improved, demand to drill deeper and longer horizontal wells has once again strengthened demand for higher horsepower rigs. All of these factors ultimately affect the demand and mix of the type of drilling rigs used by our customers.

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As of December 31, 2013, we had 23 term drilling contracts with original terms ranging from six months to three years. Twenty-two of these contracts are up for renewal in 2014, seven in the first quarter, ten in the second quarter, and five in the fourth quarter and one is up for renewal in 2015. 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.
In the second quarter of 2013, we sold one of our 2,000 horsepower electric drilling rigs. During the third and fourth quarters of 2013, we sold three additional 2,000 horsepower and one 3,000 horsepower electric drilling rigs. All of these sales were to unaffiliated third-parties. Four additional idle 3,000 horsepower drilling rigs were sold to an unaffiliated third party in the first quarter of 2014 all of which were classified as assets held for sale at December 31, 2013. The proceeds from these various sales will be used in our new drilling rig program we launched to design and build a new proprietary 1,500 horsepower, AC electric drilling rig, called the BOSS rig. We anticipate the BOSS drilling rig will position us to more effectively meet the demands of our existing customers as well as allowing us to compete for the work of new customers.

Our anticipated 2014 capital expenditures for this segment are $132.0 million, a 105% increase over 2013. The first BOSS drilling rig will be operational the first quarter of 2014 and will work initially for our oil and natural gas segment. Two additional BOSS drilling rigs are contracted to third party operators and are anticipated to be placed into service in the second and third quarters of 2014.

Mid-Stream

Fourth quarter 2013 liquids sold per day increased 12% over the third quarter of 2013 and increased 49% over the fourth quarter of 2012. During the third quarter 2012, one of our producers completed construction of their own processing plant and moved their volumes off our system resulting in decreases in liquids sold, gas gathered, and gas processed. In addition, during the fourth quarter of 2012, certain processing plants were rejecting ethane due to weak ethane prices. For the fourth quarter of 2013, gas processed per day increased 3% over the third quarter of 2013 and increased 13% over the fourth quarter of 2012. We upgraded several of our existing processing facilities and added processing plants which was the primary reason for increased volumes. For the fourth quarter of 2013, gas gathered per day decreased 4% from the third quarter of 2013 and increased 12% over the fourth quarter of 2012. The decrease during the fourth quarter of 2013 was primarily due to the transfer of one system to the oil and natural gas segment. The increase over the fourth quarter of 2012 was primarily from well connects throughout 2013.

NGLs prices in the fourth quarter of 2013 increase