10-K 1 d264723d10k.htm FORM 10-K Form 10-K
Table of Contents

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, 2011

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, 2011, 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, 2011) held by non-affiliates was approximately $1,759,458,732. Determination of stock ownership by non-affiliates was made solely for the purpose of this requirement, and the registrant is not bound by these determinations for any other purpose.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

Class

  

Outstanding at February 10, 2012

Common Stock, $0.20 par value per share

   48,247,040 shares

DOCUMENTS INCORPORATED BY REFERENCE

 

Document

  

Parts Into Which Incorporated

Portions of the registrant’s definitive proxy statement (the “Proxy Statement”) with respect to its annual meeting of shareholders scheduled to be held on May 2, 2012. 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 124


Table of Contents

FORM 10-K

UNIT CORPORATION

TABLE OF CONTENTS

 

          Page  
  

PART I

  

Item 1.

   Business      1   

Item 1A.

   Risk Factors      25   

Item 1B.

   Unresolved Staff Comments      41   

Item 2.

   Properties      41   

Item 3.

   Legal Proceedings      41   

Item 4.

   Mine Safety Disclosures      42   
  

PART II

  

Item 5.

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

 

42

  

     

Item 6.

   Selected Financial Data      44   

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operation      44   

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk      71   

Item 8.

   Financial Statements and Supplementary Data      73   

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      113   

Item 9A.

   Controls and Procedures      113   

Item 9B.

   Other Information      113   
  

PART III

  

Item 10.

   Directors, Executive Officers and Corporate Governance      114   

Item 11.

   Executive Compensation      116   

Item 12.

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

 

116

  

     

Item 13.

   Certain Relationships and Related Transactions, and Director Independence      117   

Item 14.

   Principal Accounting Fees and Services      117   
  

PART IV

  

Item 15.

   Exhibits, Financial Statement Schedules      118   

Signatures

     123   

Exhibit Index

     124   


Table of Contents

DEFINITIONS

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 to six Mcf of natural gas.

Bbl – Barrel, or 42 U.S. gallons liquid volume.

Boe – Barrel of oil equivalent.

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.


Table of Contents

DEFINITIONS – (Continued)

 

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 and oil property with existing production.

Proved developed reserves – Are reserves from any category 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 is by means not involving a well. 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 indicated 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 – Is 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, coal bed or 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 stimulation treatments or other special recovery processes in order to produce economically.


Table of Contents

DEFINITIONS – (Continued)

 

Undeveloped acreage – Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial 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.


Table of Contents

UNIT CORPORATION

Annual Report

For The Year Ended December 31, 2011

PART I

 

Item 1. Business

Unless otherwise indicated or required by the context, the terms “corporation”, “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, or at 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 Nomination 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 relations section of our website, as allowed by SEC rules.

GENERAL

We were founded in 1963 as a 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:

 

   

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.

 

   

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.

 

   

Mid-stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes and treats natural gas for third parties and for our own account.

Each of these companies may conduct operations through subsidiaries of their own.

The following table provides certain information about us as of February 10, 2012:

 

Number of drilling rigs owned

     127   

Completed gross wells in which we own an interest

     8,823   

Number of natural gas treatment plants owned

     3   

Number of processing plants owned

     10   

Number of natural gas gathering systems owned

     35   

 

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2011 SEGMENT OPERATION HIGHLIGHTS

Contract Drilling

 

   

Averaged 76.1 drilling rigs used, an increase of 24% over the average of 61.4 drilling rigs used during 2010.

 

   

Built seven new 1,500 horsepower, diesel-electric drilling rigs for our Rocky Mountain division. Five were placed in service in the Bakken Shale in North Dakota, one was placed in service in Western Wyoming and the other one is to be placed into service in Western Wyoming in the first quarter of 2012.

 

   

During the year, 19 of our drilling rigs were either refurbished, upgraded or returned into service after previously being stacked for use to meet increasing horizontal drilling activity.

Oil and Natural Gas

 

   

Attained net proved oil, natural gas liquids (NGLs) and natural gas reserves of 116.0 million barrels of oil equivalents (MMBoe), a 12% increase over end of 2010 reserves.

 

   

Increased net proved oil and NGL reserves 26% over 2010.

 

   

Total production of 12.1 MMBoe or 23% over 2010.

 

   

Participated in the drilling of 160 wells.

 

   

Acquired 12,000 net held by production acres, 30 operated wells and 59 non-operated wells located mainly in Harper, Ellis and Beaver Counties, Oklahoma from certain unaffiliated third parties.

 

   

Acquired 55,000 net acres (96% of which is held by production) and 500 wells located principally in the Oklahoma Arkoma, Woodford and Hartshorne Coal plays along with other properties from certain unaffiliated third parties.

Mid-Stream

 

   

Gas processed increased 41% over 2010.

 

   

Completed construction of a new gathering system and gas processing plant in Grant County, Oklahoma.

 

   

Completed the construction of a16-mile, 16” pipeline and accompanying compressor station in Preston County, West Virginia.

 

   

Added an additional 74 miles of pipeline (approximately a 9% increase) and connected 62 new wells to its gathering systems.

 

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Table of Contents

FINANCIAL INFORMATION ABOUT SEGMENTS

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

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 for a wide range of other oil and natural gas companies. Our drilling operations are mainly located in Oklahoma, Texas, Louisiana, Wyoming, Colorado, Utah, Montana and North Dakota.

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

 

     Year Ended December 31,  
     2011     2010     2009  

Number of drilling rigs owned at end of year

     127.0        121.0        130.0   

Average number of drilling rigs owned during year

     123.7        123.9        130.8   

Average number of drilling rigs utilized

     76.1        61.4        38.9   

Utilization rate (1)

     61     50     30

Average revenue per day (2)

   $ 17,455      $ 14,115      $ 16,662   

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

     9,749        7,961        4,627   

Number of wells drilled

     742        593        409   

 

(1) Utilization rate is determined by dividing the average number of drilling rigs used by the average number of drilling rigs owned during the year.

 

(2) Represents the total revenues from our contract drilling operations divided by the total number of days our drilling rigs were used during the year.

Description and Location of Our Drilling Rigs.    An on-shore drilling rig is composed of major equipment components, such as engines, drawworks or hoists, derrick or mast, substructure, pumps to circulate the drilling fluid, blowout preventers and drill pipe that are collectively unitized into an operating system commonly referred to as a drilling rig. As a result of the normal wear and tear of operating 24 hours a day, several of the major components of a drilling rig, like engines, mud pumps and drill pipe, must be replaced or rebuilt on a periodic basis. Other 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 2011, 85 of our 127 drilling rigs were used in drilling services.

 

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The following table shows certain information about our drilling rigs (including their distribution) as of February 10, 2012:

 

Region

   Contracted
Rigs
     Non-Contracted
Rigs
     Total
Rigs
     Average
Rated
Drilling
Depth
(ft)
 

Anadarko Basin—Oklahoma and Texas Panhandle

     49         25         74         16,142   

Arkoma Basin

     2         3         5         13,900   

East Texas, Louisiana, Gulf

           

Coast and South Texas

     11         7         18         17,611   

Rocky Mountains

     21         9         30         18,100   
  

 

 

    

 

 

    

 

 

    

 

 

 

Totals

     83         44         127         16,724   
  

 

 

    

 

 

    

 

 

    

 

 

 

With the downturn in drilling activity that started in the fourth quarter of 2008, we consolidated our nine operating divisions into six at the beginning of 2009 to minimize our costs. Currently our operating divisions consist of the following: Arkoma, Gulf Coast, Mid-Continent, Panhandle, Rocky Mountain and Woodward.

Drilling rig utilization steadily increased throughout 2010 and 2011. In the middle of 2009 our active rig count reached a low of 28 rigs. Our active rig count at the beginning of 2010 was 42 rigs and increased to 82 rigs to finish out 2011.

Anadarko Basin.    The Anadarko Basin is a geologic feature covering approximately 50,000 square miles primarily in Central and Western Oklahoma, but also includes the upper Texas Panhandle, southwestern Kansas and southeastern Colorado region. The basin contains sedimentary deposits ranging in thickness from 2,000 feet on its northern and western flanks to 40,000 feet in its southern portion.

During 2011, our Mid-Continent, Panhandle and Woodward divisions working in the Anadarko Basin area averaged 24.0, 9.1 and 8.9 drilling rigs operating, respectively. Part of the increased activity in this area stems from the oil and NGL interest by operators working primarily in the Cana Woodford , Granite Wash, Marmaton and Mississippi horizontal plays.

Arkoma Basin.    The Arkoma Basin is another geologic feature that encompasses approximately 33,800 square miles of southeastern Oklahoma and west-central Arkansas. The Arkoma Basin holds deposits ranging in thickness from 3,000 to 20,000 feet. It contains multiple conventional gas plays as well as two of the more recent notable unconventional plays—the Woodford Shale and Fayetteville Shale.

During 2011, our Arkoma division averaged 3.6 drilling rigs operating. The Arkoma Basin has traditionally been a natural gas play. With lower natural gas commodity prices during 2011 and operators shifting their drilling emphasis to liquids, we moved one rig from this division to our Mid-Continent division for greater utilization. Additionally, we reactivated two stacked, lower horsepower rigs and moved into southern Oklahoma drilling oil and liquids rich programs.

East Texas, Louisiana, Gulf Coast and South Texas.    Our Gulf Coast division provides drilling rigs to the onshore areas of the south Louisiana Gulf Coast and upper Texas Gulf Coast region as well as the conventional and unconventional gas plays of northwest Louisiana, East Texas and South Texas. The Gulf Coast division averaged 12.9 drilling rigs operating for the year. The Haynesville Shale play was an active area for us with six rigs working there during most of 2011. As natural gas prices declined in 2011, rig activity in the Haynesville Shale began to slow and we moved four rigs out of this area, two were relocated to the Mid-Continent division, one relocated to South Texas and one was recently relocated to the Arkoma division. At year-end 2011, we had two rigs operating in the Haynesville area and six rigs in the Eagle Ford area.

 

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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. Our drilling rig fleet in this division operated an average of 17.6 drilling rigs during 2011. We have drilling rigs operating primarily in the Pinedale Anticline of western Wyoming and the Bakken Shale of North Dakota, as well as other areas throughout this expansive geographical area. We ended 2011 with 14 drilling rigs working in the Bakken Shale, including six new build rigs that were constructed and placed into service during 2011. Additionally, one new 1,500 horsepower electric drilling rig is rigging up to begin operations during the first quarter of 2012. As mentioned earlier, we are in the process of building another 1,500 horsepower electric drilling rig that will be deployed in the second quarter of 2012 to the Bakken Shale.

At any given time the number of our drilling rigs we can work is dependent on a number of conditions besides demand, including the availability of qualified labor and the availability of needed drilling supplies and equipment. Not surprisingly, the impact of these various conditions tends to fluctuate with the demand for our drilling rigs. Our utilization rate was significantly affected by the U.S. and world economic downturn starting in late 2008. For 2009, our average utilization rate declined to 30%, for 2010 our average utilization rate increased to 50%, and by 2011 it was 61%.

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

 

     2011      2010      2009  

First quarter

     70.0         50.9         52.8   

Second quarter

     73.1         58.1         31.6   

Third quarter

     78.9         65.4         34.6   

Fourth quarter

     82.1         70.9         36.7   

Drilling Rig Fleet.    The following table summarizes the changes made to our drilling rig fleet in 2011. A more complete discussion of these changes follows the table:

 

Drilling rigs owned at December 31, 2010

     121   

Drilling rigs sold

       

Drilling rigs purchased

       

Drilling rigs constructed

     6   
  

 

 

 

Total drilling rigs owned at December 31, 2011

     127   
  

 

 

 

Dispositions, Acquisitions, and Construction.    During 2009, we sold three mechanical drilling rigs (ranging in horsepower from 750 to 1,000) for $8.6 million and recorded a $4.8 million gain and acquired one new 1,500 horsepower diesel electric drilling rig for $13.2 million.

During the first half of 2010, our contract drilling segment sold eight of its idle mechanical drilling rigs to an unaffiliated third party. These drilling rigs ranged in horsepower from 800 to 1,000. Proceeds from the sale of those drilling rigs were $23.9 million with a gain of $5.7 million which was recorded in the first quarter 2010. The proceeds were used to refurbish and upgrade existing drilling rigs in our fleet allowing those drilling rigs to be used in horizontal drilling operations. We also placed into service in our Rocky Mountain division a 1,500 horsepower, diesel-electric drilling rig that previously had been placed on hold during 2009 by our customer.

In September 2010, we entered into a contract with an unaffiliated third-party under which we conveyed three of our idle mechanical drilling rigs and, in exchange, we received a 1,200 horsepower electric drilling rig and $5.3 million. The three drilling rigs sold ranged in horsepower from 650 to 1,000. The transaction closed in October and resulted in a gain of $3.5 million.

 

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At the end of 2010, we began constructing five new 1,500 horsepower, diesel-electric drilling rigs. All of these drilling rigs are now working in the Bakken shale in North Dakota under two-year drilling contracts.

During the third quarter of 2011, we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. These new build rigs will initially be working under three year contracts. One was placed into service during the fourth quarter of 2011 and the other will be placed in service during the first quarter of 2012.

During the fourth quarter of 2011, we entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be used in North Dakota starting in the second quarter of 2012. This new build rig will initially be working under a three year contract.

Subsequent to the 2011 year-end, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third party.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. However, with the current weakened natural gas market, operators are now focusing on drilling for oil and NGLs. Today, approximately 93% of our working drilling rigs are drilling for oil or NGLs. Of those, approximately 98% are drilling horizontal or directional wells.

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 personnel, maintenance expenses and incidental drilling rig supplies and equipment. The contracts are usually subject to early termination by the customer with 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 contracts in 2011, we drilled four wells under a footage contract in 2010 and one well in 2009. 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.

Under turnkey contracts we may incur losses if we underestimate the costs to drill the well or if unforeseen events occur that increase our costs or result in the loss of the well. We have not worked under a turnkey contract during the last three years. With the exception of the footage contracts noted above, 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, depending on the contract, the rates can either be fixed throughout the term or allow for periodic adjustments.

 

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Customers.    During 2011, QEP Resources, Inc. was our largest drilling customer accounting for approximately 22% of our total contract drilling revenues. Our work for this customer was under multiple contracts and our business was not substantially dependent on any of these individual contracts. Consequently, none of these contracts on their own 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 2011, 2010 and 2009, we drilled 81, 75 and 38 wells, respectively, or 11%, 13% and 9%, respectively, of the total wells drilled by our drilling segment. Depending on the timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for these services are eliminated in our 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 same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $52.2 million, $40.1 million and $15.0 million during 2011, 2010 and 2009, respectively from our contract drilling segment and eliminated the associated operating expense of $32.6 million, $31.0 and $13.7 million during 2011, 2010 and 2009, respectively, yielding $19.6 million, $9.1 million and $1.3 million during 2011, 2010 and 2009, respectively, as a reduction to the carrying value of our oil and natural gas properties.

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, undeveloped leaseholds and related assets are located mainly in Oklahoma, Texas, Louisiana, North Dakota and, to a lesser extent, in Arkansas, New Mexico, Wyoming, Montana, Alabama, Kansas, Mississippi, Michigan, Colorado and Pennsylvania and a small portion in Canada.

When we are the operator of a property, we generally attempt to use a drilling rig owned by our contract drilling segment.

The following table presents certain information regarding our oil and natural gas operations as of December 31, 2011:

 

Our Divisions/Area

  Number
of
Gross
Wells
    Number
of Net
Wells
    Number
of Gross
Wells in
Process
    Number
of Net
Wells in
Process
    2011 Average
Net Daily Production
 
          Natural
Gas
(Mcf)
    Oil
(Bbls)
    NGL
(Bbls)
 

West division (consists principally of the Rocky Mountain region, New Mexico, Western and Southern Texas and the Gulf Coast region)

    3,308        534.37        11        5.60        32,258        2,446        2,186   

East division (consists principally of the Appalachian region, Arkansas, East Texas, Northern Louisiana and Eastern Oklahoma)

    1,697        526.32        2        0.46        34,979        33        14   

Central division (consists principally of Kansas, Western Oklahoma and the Texas Panhandle)

    3,806        986.07        13        4.46        53,596        4,401        3,934   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    8,811        2,046.76        26        10.52        120,833        6,880        6,134   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

As of December 31, 2011, we did not have any significant water floods, pressure maintenance operations, or any other material operations that were in process.

 

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Description and Location of Our Core Operations

West division.    Our Wilcox play, located primarily in Polk, Tyler and Hardin Counties, Texas, continues to grow. For 2011, we operated and completed 17 wells with an average working interest of 97%. The net production from this area for the fourth quarter 2011 averaged 1,562 barrels of oil per day, 1,486 barrels of NGLs per day and 24.5 MMcf per day, or an equivalent rate of 42.7 MMcfe per day, an increase of 34% from the fourth quarter of 2010. For 2012, we plan to drill approximately 15 gross wells with an approximate working interest of 87% for an estimated cost of $41 million. We hold approximately 26,000 net leasehold acres in the Wilcox play. We have entered into a development agreement covering approximately 47,000 net mineral acres and have acquired lease options covering approximately 82,000 net mineral acres in the expanded area.

In the Bakken play located in North Dakota, we participated in 17 wells in 2011 at an average working interest of 11% and a total net cost of approximately $18 million. The average ultimate recovery for a Bakken horizontal well is estimated to be 662 thousand barrels of oil equivalent (MBoe) per well. The net production from our Bakken play for the fourth quarter 2011 averaged approximately 831 barrels of oil per day and 977 Mcf per day, an increase of 42% from the fourth quarter of 2010. For 2012, we anticipate participating in approximately 20 gross wells with an average working interest of 10% to 15% at a total net cost of approximately $30 million. We own approximately 13,400 net acres in the play and anticipate two to three rigs drilling on its North Dakota Bakken leasehold during 2012.

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.    During 2011, we drilled 34 wells with an average working interest of 87% in our Marmaton horizontal oil play located in Beaver County, Oklahoma. The initial 30-day average production rate for the 34 wells ranged from 20 barrels of oil equivalent (Boe) per day to 930 Boe per day with an average rate of 308 Boe per day. The average ultimate recovery for a Marmaton horizontal well is estimated to be 130 MBoe, which is comprised of approximately 78% oil, 14% NGLs and 8% natural gas. The average completed well cost is approximately $2.7 million. The net production from our Marmaton operated wells for the fourth quarter 2011 averaged 2,295 barrels of oil per day, 321 barrels NGLs per day, and 1,077 Mcf per day, an increase of 46% over the third quarter 2011 and a 176% increase over the fourth quarter 2010. For 2012, we anticipate running a two drilling rig program in this play that should result in 30 to 35 gross wells at an approximate net cost of $61 million to $71 million. We plan to drill our first 9,000’ extended lateral in this play during the first quarter of 2012 for an estimated cost of $4.2 million. The average lateral length drilled to date is 4,100 feet. We currently have leases on approximately 92,262 net acres in this play.

In our Granite Wash (GW) play located in the Texas Panhandle, we drilled and operated 16 horizontal wells with an average working interest of 76% during 2011. The 30-day average production rate for the 16 wells was 6.8 MMcfe per day. The GW laterals completed in 2011 targeted six different GW sands with 44% of the laterals drilled in the GW “B” interval. The average ultimate recovery for a GW horizontal well is estimated to be 4.6 Bcfe, which is comprised of 13% oil, 37% NGLs and 50% natural gas. The average completed well cost is approximately $5.5 million. The net production from our GW operated wells for the fourth quarter 2011 averaged 1,136 barrels of oil per day, 3,065 barrels NGLs per day and 24.8 MMcf per day, or an equivalent rate of 50.5 MMcfe per day, an increase of 2% over the third quarter 2011 and a 59% increase over the fourth quarter 2010. We expect to work three to four Unit drilling rigs drilling horizontal wells in 2012 which equates to approximately 20 operated GW wells with an approximate net cost of $90 million.

We have recently acquired approximately 60,000 net acres located primarily in south central Kansas in the developing Mississippian play. The current plans are to drill three to four horizontal wells in the next six months and evaluate the results before planning any further drilling in this play.

 

Dispositions and Acquisitions.    There were no material dispositions during 2011 or 2010.

On June 2, 2010, we completed an acquisition of oil and natural gas properties from certain unaffiliated parties in an effort to explore and develop more oil rich plays. The properties were purchased for approximately

 

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$73.7 million in cash, after post closing adjustments. The purchase price allocation was $48.7 million for proved properties and $25.0 million for undeveloped leasehold not being amortized. The acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells. This acquisition targeted the Marmaton horizontal oil play located mainly in Beaver County, Oklahoma. At the time of acquisition, proved developed producing net reserves associated with the 10 acquired producing wells was approximately 762,000 BOE — consisting of 511,000 barrels of oil, 155,000 barrels of NGLs and 573 MMcf of natural gas.

Also during the second quarter of 2010, we completed an acquisition from unaffiliated parties consisting of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million.

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 in Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The net proved developed reserves associated with the acquisition are estimated at 6.6 Bcfe (91% natural gas) with production of 1.7 MMcfe per day. 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, subject to closing adjustments, 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 proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

During the fourth quarter of 2011, we leased approximately 60,000 net acres of undeveloped oil and gas leasehold located in south central Kansas for approximately $17.3 million.

 

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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,  
     2011        2010        2009  
     Gross      Net        Gross      Net        Gross      Net  

Wells drilled:

                     

Exploratory:

                     

Oil:

                     

West division

     0         0           3         1.41           2         0.28   

East division

     0         0           0         0           0         0   

Central division

     0         0           1         1.00           0         0   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total oil

     0         0           4         2.41           2         0.28   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Natural gas:

                     

West division

     5         4.13           4         4.00           3         2.50   

East division

     0         0           0         0           0         0   

Central division

     0         0           1         0.05           0         0   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total natural gas

     5         4.13           5         4.05           3         2.50   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Dry:

                     

West division

     7         6.50           5         4.12           3         2.10   

East division

     0         0           0         0           0         0   

Central division

     0         0           0         0           0         0   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total dry

     7         6.50           5         4.12           3         2.10   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total exploratory

     12         10.63           14         10.58           8         4.88   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Development:

                     

Oil:

                     

West division

     21         4.57           25         4.69           14         3.54   

East division

     0         0           0         0           0         0   

Central division

     56         32.81           43         25.90           6         1.80   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total oil

     77         37.38           68         30.59           20         5.34   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Natural gas:

                     

West division

     9         6.26           13         10.85           1         1.00   

East division

     9         4.65           19         11.47           35         16.96   

Central division

     44         18.32           42         18.22           28         12.77   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total natural gas

     62         29.23           74         40.54           64         30.73   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Dry:

                     

West division

     3         2.03           4         1.51           1         0.80   

East division

     1         1.00           1         0.36           1         0.16   

Central division

     5         2.15           6         3.94           1         0.60   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total dry

     9         5.18           11         5.81           3         1.56   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total development

     148         71.79           153         76.94           87         37.63   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total wells drilled

     160         82.42           167         87.52           95         42.51   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

 

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     Year Ended December 31,  
     2011        2010        2009  
     Gross      Net        Gross      Net        Gross      Net  

Wells producing or capable of producing:

                     

Oil:

                     

West division

     2,074         183.50           2,052         178.85           2,051         178.85   

East division

     54         3.17           52         2.58           52         2.75   

Central division

     631         273.31           552         234.05           552         227.73   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total oil

     2,759         459.98           2,656         415.48           2,655         409.33   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Natural gas:

                     

West division

     1,182         335.90           1,167         324.33           1,128         314.37   

East division

     1,636         522.15           1,086         290.04           1,052         266.04   

Central division

     3,097         683.08           2,927         611.05           2,868         580.57   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total natural gas

     5,915         1,541.13           5,180         1,225.42           5,048         1,160.98   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total

     8,674         2,001.11           7,836         1,640.90           7,703         1,570.31   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

As of February 10, 2012, we had participated in 12 gross (7.33 net) wells started during 2012.

Cost incurred for development drilling includes $111.4 million, $84.6 million and $24.5 million in 2011, 2010 and 2009, respectively, to develop booked proved undeveloped oil and natural gas reserves.

The following table summarizes our leasehold acreage at December 31, 2011:

 

     Year Ended December 31, 2011  
     Developed        Undeveloped        Total  
     Gross      Net        Gross      Net (1)        Gross      Net  

West division

     318,063         104,221           208,615         113,158           526,678         217,379   

East division

     266,693         113,720           218,531         68,230           485,224         181,950   

Central division

     660,656         217,946           228,374         161,776           889,030         379,722   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

Total

     1,245,412         435,887           655,520         343,164           1,900,932         779,051   
  

 

 

    

 

 

      

 

 

    

 

 

      

 

 

    

 

 

 

 

(1) Approximately 83% (West – 67%; East – 83% and Central – 94%) of the net undeveloped acres are covered by leases that will expire in the years 2012—2014 unless drilling or production extends the terms of those leases.

The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United States for the years 2012—2016, as disclosed in our December 31, 2011 oil and natural gas reserve report, are $159.1 million, $124.9 million, $7.4 million, $2.8 million and $1.0 million, respectively.

 

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Price and Production Data.    The following tables identify the average sales price, oil, NGLs and natural gas 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,  
     2011     2010     2009  

Average sales price per barrel of oil produced:

      

Price before hedging

   $ 93.49      $ 76.65      $ 56.64   

Effect of hedging

     (6.31     (7.13     (0.31
  

 

 

   

 

 

   

 

 

 

Price including hedging

   $ 87.18      $ 69.52      $ 56.33   
  

 

 

   

 

 

   

 

 

 

Average sales price per barrel of NGLs produced:

      

Price before hedging

   $ 44.44      $ 36.96      $ 25.66   

Effect of hedging

     (0.80     0.08        (2.85
  

 

 

   

 

 

   

 

 

 

Price including hedging

   $ 43.64      $ 37.04      $ 22.81   
  

 

 

   

 

 

   

 

 

 

Average sales price per Mcf of natural gas produced:

      

Price before hedging

   $ 3.78      $ 4.05      $ 3.26   

Effect of hedging

     0.48        1.57        2.33   
  

 

 

   

 

 

   

 

 

 

Price including hedging

   $ 4.26      $ 5.62      $ 5.59   
  

 

 

   

 

 

   

 

 

 

 

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Table of Contents

 

     Year Ended December 31,  
     2011      2010      2009  

Oil production (MBbls):

        

West division

     893         729         648   

East division

     12         14         13   

Central division:

        

Mendota field

     262         149         138   

All other central division fields

     1,344         629         487   
  

 

 

    

 

 

    

 

 

 

Total central division

     1,606         778         625   
  

 

 

    

 

 

    

 

 

 

Total oil production (MBbls)

     2,511         1,521         1,286   
  

 

 

    

 

 

    

 

 

 

NGL production (MBbls):

        

West division

     798         627         699   

East division

     5         4         5   

Central division:

        

Mendota field

     691         494         475   

All other central division fields

     745         424         309   
  

 

 

    

 

 

    

 

 

 

Total central division

     1,436         918         784   
  

 

 

    

 

 

    

 

 

 

Total NGL production (MBbls)

     2,239         1,549         1,488   
  

 

 

    

 

 

    

 

 

 

Natural gas production (MMcf):

        

West division

     11,774         10,946         12,395   

East division

     12,768         14,029         14,639   

Central division:

        

Mendota field

     4,887         4,050         4,227   

All other central division fields

     14,675         11,731         12,802   
  

 

 

    

 

 

    

 

 

 

Total central division

     19,562         15,781         17,029   
  

 

 

    

 

 

    

 

 

 

Total natural gas production (MMcf)

     44,104         40,756         44,063   
  

 

 

    

 

 

    

 

 

 

Total production (MBoe):

        

West division

     3,653         3,180         3,412   

East division

     2,145         2,356         2,458   

Central division:

        

Mendota field

     1,768         1,318         1,318   

All other central division fields

     4,535         3,009         2,930   
  

 

 

    

 

 

    

 

 

 

Total central division

     6,303         4,327         4,248   
  

 

 

    

 

 

    

 

 

 

Total production (MBoe)

     12,101         9,863         10,118   
  

 

 

    

 

 

    

 

 

 

Average production cost per equivalent Bbl

   $ 9.54       $ 9.24       $ 8.70   

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

 

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Oil, NGL and Natural Gas Reserves.    The following table identifies our estimated proved developed and undeveloped oil, NGLs and natural gas reserves:

 

     Year Ended December 31, 2011  
     Natural
Gas
(MMcf)
     Oil
(MBbls)
     NGL
(MBbls)
     Total
Proved
Reserves
(MBoe)
 

Proved developed:

           

West division

     70,299         5,490         4,403         21,610   

East division

     131,883         87         70         22,137   

Central division

     170,129         10,041         12,176         50,572   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved developed

     372,311         15,618         16,649         94,319   
  

 

 

    

 

 

    

 

 

    

 

 

 

Proved undeveloped:

           

West division

     6,031         2,214         306         3,525   

East division

     14,841         0         0         2,473   

Central division

     48,952         2,423         5,132         15,714   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved undeveloped

     69,824         4,637         5,438         21,712   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total proved

     442,135         20,255         22,087         116,031   
  

 

 

    

 

 

    

 

 

    

 

 

 

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 comprised the top 82% of the total proved developed discounted future net income and 96% of the total proved undeveloped discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by us as of December 31, 2011.

Our Reservoir Engineering department is responsible for reserve determination for all wells in which we have an interest. Their primary objective is to estimate our future reserves and their 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 and the company’s internal audit group has a checklist of review tasks to confirm the correctness of data transfer. 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 was the primary technical person designated to be in charge on behalf of Ryder Scott for our audit of reserves.

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

 

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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.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Richoux fulfills. As part as his 2011 continuing education hours, Mr. Richoux attended 29 hours of formalized in-house and external training.

Based on his educational background, professional training and more than 40 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Richoux has attained the professional qualifications as a Reserve Estimator [requires appropriate degree and/or is registered as Professional Engineer and has a minimum of three years experience in the estimation and evaluation of reserves] and Reserve 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 five 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 website at http://www.ryderscott.com/Experience/Employees.

Unit Corporation – Responsibility for overseeing the preparation of the company’s reserve report is shared by its 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 33 of his 40 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 the recent changes that have occurred in SEC rules pertaining to 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 – 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 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.

 

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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 (LKH) 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 (HKO) elevation and the potential exist for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

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

 

   

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or other evidence using reliable technology establishes reasonable certainty of the engineering analysis on which the project or program was based; and

 

   

The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to 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 such period, unless prices are defined by contractual arrangements, excluding escalations based upon 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 recompletion. Reserves on undrilled acreage shall be 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 shall 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, 2011, we had approximately 121 gross proved undeveloped wells (PUDs) all of which we plan to develop within five years at a net estimated cost of approximately $295.1 million. We do not have any aged PUDs (PUDs greater than five years). During 2011, we converted 38 PUDs into proved developed wells (PDPs) at a cost of approximately $111.4 million.

 

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Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2011, 2010, and 2009, the changes in quantities and standardized measure of such 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 2011, Valero Energy Corporation and Sunoco Partners Marketing accounted for 18% and 10%, respectively, of our oil and natural gas revenues. During 2011, our mid-stream segment purchased $71.5 million of our natural gas and NGLs production and provided gathering and transportation services of $4.6 million. Intercompany revenue from services and purchases of production between our mid-stream segment and our oil and natural gas segment has been eliminated in our consolidated financial statements. In 2010 and 2009, we eliminated intercompany revenues of $46.8 million and $33.9 million, respectively, attributable to the production of natural gas and NGLs as well as gathering and transportation services.

MID-STREAM

General.    Our mid-stream operations are conducted through Superior Pipeline Company L.L.C. Its operations consist of primarily in the buying, selling, gathering, processing and treating of natural gas. In addition, it operates three natural gas treatment plants, 10 operating processing plants, 35 active gathering systems and 934 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,  
     2011      2010      2009  

Gas gathered—MMBtu/day

     215,805         183,867         183,989   

Gas processed—MMBtu/day

     116,161         82,175         75,908   

NGLs sold—gallons/day

     412,064         271,360         243,492   

Dispositions and Acquisitions.    This segment did not have any significant dispositions or acquisitions during 2011 or 2010.

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, 2011, 42% of our mid-stream segment’s total volumes and 14% 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 remitted to the producer. In this arrangement, Superior and the producers are directly dependent on the volume of the commodity and its value; Superior owns a

 

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percentage of that commodity and is directly subject to fluctuations in its market value. For the year ended December 31, 2011, 52% of our mid-stream segment’s total volumes and 57% of operating margins (as defined below) were under POP contracts.

 

   

Percent of Index Contracts (POI).    Under these contracts our mid-stream’s 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, 2011, 6% of our mid-stream segment’s total volumes and 29% 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 2011, ONEOK and Gavilon, LLC accounted for approximately 54% and 19%, respectively, of our mid-stream revenues. We believe that if we lost one or both of these identified customers, there are other customers available to purchase our gas and liquids.

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. The following table shows for each of the periods indicated 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        NGL Price per Bbl        Natural Gas
Price per Mcf
 

Quarter

   High      Low        High      Low        High      Low  

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   

2010:

                     

Fourth

   $ 85.37       $ 78.20         $ 43.34       $ 38.01         $ 4.00       $ 2.87   

Third

   $ 72.69       $ 72.23         $ 33.05       $ 29.15         $ 4.43       $ 3.12   

Second

   $ 81.18       $ 71.19         $ 36.20       $ 31.29         $ 3.99       $ 3.37   

First

   $ 78.08       $ 73.83         $ 43.39       $ 41.50         $ 5.57       $ 4.47   

2009:

                     

Fourth

   $ 75.11       $ 71.76         $ 43.22       $ 31.12         $ 4.38       $ 3.35   

Third

   $ 67.62       $ 60.69         $ 27.38       $ 21.38         $ 3.30       $ 2.37   

Second

   $ 66.48       $ 39.93         $ 27.30       $ 21.34         $ 2.90       $ 2.59   

First

   $ 42.26       $ 34.75         $ 19.95       $ 17.89         $ 4.67       $ 2.45   

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, including the Middle East, Nigeria and Venezuela;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries to agree on prices and their ability to maintain production quotas;

 

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the price of foreign oil imports;

 

   

imports 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;

 

   

the price, availability and acceptance of alternative fuels; and

 

   

overall 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 and natural gas prices affect demand. Because oil and natural gas prices are volatile, the level of demand for our services can also be volatile. Both demand for our drilling rigs and dayrates steadily declined throughout 2009. This was followed by a gradual increase in activity (as well as dayrates) during 2010 and 2011.

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 pipelines. Margins received for the delivery of these natural gas and NGLs are dependent on the price for oil, natural gas and natural gas liquids and the demand for natural gas and NGLs in our area of operations. If the price of NGLs falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to us to extract certain NGLs. The volumes of natural gas and NGLs processed are highly dependent on the volume and Btu content of the natural gas and NGLs gathered.

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.

 

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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 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 explorationists, engineers and other professionals. Competition for these professionals can be extremely intense, particularly when the industry is experiencing favorable conditions.

Our oil and natural gas operations likewise encounter strong competition from other oil and 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 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 systems and deliver the natural gas and NGLs once the gathering 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 gas limited partnerships. Three of these partnerships were formed for investment by third parties and 13 (the employee partnerships) were formed to allow our employees and directors the opportunity to participate with Unit Petroleum Company in its operations. The partnerships formed for use in connection with third party investments were formed in 1984 and 1986. One employee partnership has been formed each year beginning with 1984 and ending with 2011.

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

Under the terms of our partnership agreements, the general partner has broad discretionary authority to manage the business and operations of the partnership, including the authority to make decisions regarding the partnership’s participation in a drilling location or a property acquisition, the partnership’s expenditure of funds and the distribution of funds to partners. Because the business activities of the limited partners and the general partner are not the same, conflicts of interest will exist and it is not possible to entirely eliminate these conflicts. Additionally, conflicts of interest may arise when we are the operator of an oil and natural gas well and also provide contract drilling services. In these cases, the drilling operations are conducted under drilling contracts containing terms and conditions comparable to those contained in our drilling contracts with non-affiliated operators. We believe we fulfill our responsibility to each contracting party and comply fully with the terms of the agreements which regulate these conflicts.

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

 

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EMPLOYEES

As of February 10, 2012, we had approximately 2,244 employees in our contract drilling segment, 214 employees in our oil and natural gas segment, 111 employees in our mid-stream segment and 105 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 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. We do not know what effect the FERC’s other activities will have on the access to markets, the fostering of competition and the cost of doing business.

 

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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 are other 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. Oklahoma, Texas and other states 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

 

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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.

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. 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 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 Bakken of North Dakota and Montana. 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. In addition, certain states in which we operate, including Texas 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. Any new laws, regulation or permitting requirements regarding hydraulic fracturing could lead to operational delay, or increased operating costs or third party or governmental claims, and could result in additional burdens that could serve to delay or limit the drilling services we provide to third parties whose drilling operations could be impacted by these regulations or increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

 

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Further, on July 28, 2011, the EPA issued proposed rules that would subject all 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. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business. 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.

We do not know and cannot predict whether any of the proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address GHG emissions and/or hydraulic fracturing would impact our business segments. Depending on the final provisions of such legislation, rules or ordinances, 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.

 

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS/CAUTIONARY STATEMENT AND RISK FACTORS

This report contains “forward-looking statements” – meaning, statements related to future, not past, 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 amount of wells we plan to drill or rework;

 

   

prices for oil, NGLs and natural gas;

 

   

demand for oil 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;

 

   

production of oil, NGLs and natural gas reserves;

 

   

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 or natural gas production to established pipeline systems; and

 

   

federal and state legislative and regulatory initiatives relating to hydrocarbon fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affecting our business.

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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties which could cause actual results to differ materially from our expectations, including:

 

   

the risk factors discussed in this report and in the documents we incorporate by reference;

 

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general economic, market or business conditions;

 

   

the availability of and nature 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 report to reflect the occurrence of unanticipated events.

In order to help provide you with a more thorough understanding of the possible effects of some of these influences on any forward-looking statements made by us, the following discussion outlines some (but not all) of the factors that could in the future cause our 2012 and following consolidated results to differ materially from those that may be presented in any forward-looking statement made by us or on our behalf.

Drilling Customer Demand.    With the exception of the drilling we do for our own account, the demand for our 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 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 foreign influences 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.

 

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Based on our 2011 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 $356,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $196,000 per month ($2.4 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 $175,000 per month ($2.1 million annualized) change in our pre-tax operating cash flow. During 2011, 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 58%, 18% and 66% of our 2011 average daily production for oil, NGLs and natural gas, respectively.

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. 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 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;

 

   

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. Starting December 31, 2009, companies like us that use full cost accounting moved from using the commodity prices existing on the last day of the period to that of 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

 

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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 periodically review 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%. As of December 31, 2011, 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, even if prices are depressed for only a short period of time. Before 2009, the price was based on the single-day period-end price. The revision to the 12-month average price was made to reduce the affect of short-term volatility and seasonality that previously occurred with single-day pricing. Using the 12-month average may or may not result in write-downs that would have been required had the single-day period-end price been used. 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 or unusually volatile. 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 of oil and natural gas properties is not reversible.

As a result of these ceiling test rules, we recorded a non-cash ceiling test write down of $281.2 million pre-tax ($175.1 million, net of tax) during the quarter ended March 31, 2009. No ceiling test write down was necessary during 2010 or 2011.

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.

Debt and Bank Borrowing.    We have incurred and currently expect to continue to incur substantial working capital expenditures because of the growth in our operations. Historically, we have funded our working capital needs through a combination of internally generated cash flow and borrowings under our bank credit agreement. In 2011 we issued $250.0 million of senior subordinated notes (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, 2011, our outstanding long-term debt under our credit agreement was $50.0 million and the amount of the Notes was $250.0 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;

 

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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.

 

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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 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 gas prices. Such factors include, among other things, the domestic and foreign supply of oil, NGLs and 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 natural gas market is also unsettled due to a number of factors. At times in the past, production from natural gas wells in some geographic areas of the United States was curtailed for considerable periods of time due to a lack of market demand. When demand for natural gas increased the number of wells being shut-in for lack of demand was reduced. It is possible, however, that some of our wells may in the future be shut-in or that natural gas will be sold on terms less favorable than might otherwise be obtained should demand for gas remain depressed. Competition for available markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. Natural gas surpluses could result in our inability to market natural gas profitably, causing us to curtail production and/or receive lower prices for our 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 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, including the Middle East, Nigeria and Venezuela;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries to agree on prices and their ability to maintain production quotas;

 

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the price of foreign oil imports;

 

   

imports 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 natural gas;

 

   

weather conditions;

 

   

domestic and foreign government regulations;

 

   

the price, availability and acceptance of alternative fuels; and

 

   

overall economic conditions.

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

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

Our contract drilling operations depend on the level of activity in oil, NGLs and natural gas exploration and production in our operating markets. Both short-term and long-term trends in oil, NGLs and natural gas prices affect the level of that activity. Because oil, NGLs and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Any decrease from current oil, NGLs and natural gas prices would 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.

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 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.

 

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

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

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

We have experienced and may continue to experience substantial working capital needs in the growth of our operations. We have $250.0 million of indebtedness outstanding on the Notes, and in addition, have the right to borrow up to $250.0 million under our credit agreement. As of February 10, 2012, we have outstanding borrowings of $50.0 million 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.

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

 

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reserves will decline, resulting eventually in a decrease in oil 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 cancelled 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;

 

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delays in the development of other producing properties within the gathering system’s area of operation; and

 

   

demand for natural gas and its constituents.

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

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

Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, 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

 

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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 and natural gas;

 

   

increases or decreases in consumption; and

 

   

changes in governmental regulations or taxation.

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

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

We periodically review 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, even if prices were depressed for only a short period of time. Prior to 2009, the price was based on the single-day period-end price. The revision to the 12-month average price was made to reduce the affect of short-term volatility and seasonality that previously occurred with single-day pricing. Using the 12-month average may or may not result in write-downs that would have been required had the single-day period-end price been used. 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 or unusually volatile. 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 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

 

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seek to obtain indemnification from our drilling customers by contract for some of these risks. To the extent that we are unable to transfer these risks to drilling customers by contract or indemnification agreements (or to the extent we assume obligations of indemnity or assume liability for certain risks under our drilling contracts), we seek protection from some of these risks through insurance. However, some risks are not covered by insurance and we cannot assure you that the insurance we do have or the indemnification agreements we have entered into will adequately protect us against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, or the failure of a customer to meet its indemnification obligations, could result in substantial losses. In addition, we cannot assure you that insurance will be available to cover any or all of these risks. Even if available, the insurance might not be adequate to cover all of our losses, or we might decide against obtaining that insurance because of high premiums or other costs.

In addition, we are not the operator of many of our wells. As a result, our operating risks for those wells and our ability to influence the operations for those wells are less subject to our control. Operators of those wells may act in ways that are not in our best interests.

Governmental and environmental regulations could adversely affect our business.

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

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

 

   

from a well or drilling equipment at a drill site;

 

   

from gathering systems, pipelines, transportation facilities and storage tanks;

 

   

damage to oil and natural gas wells resulting from accidents during normal operations; and

 

   

blowouts, cratering and explosions.

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

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

Certain groups have asserted efforts to have the United States Congress impose some form of price controls on either oil, natural gas or both. There is no way at this time to know what result these efforts will have nor, if implemented, their effect on our operations. However, it is possible that these efforts, if successful, would serve

 

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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, and we may be adversely affected.

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

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

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

The marketability of our oil, NGLs and natural gas production depends in part on the availability, proximity and capacity of pipeline systems, refineries and other transportation sources. The unavailability of or lack of

 

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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 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 2011, our largest customer, QEP Resources, Inc. accounted for approximately 22% of our 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 year or so, the increase in horizontal drilling activity in certain areas has 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 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 NGL 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 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. The worldwide financial and credit crisis may have adversely affected the ability of these counterparties to fulfill their obligations to us. If one or more of our counterparties is unable or unwilling to make required payments to us under our commodity derivative contracts, it could have a material adverse effect on our financial condition and results of operations.

Reliance on management.

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

 

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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. The Act requires the Commodities Futures and Trading Commission (the CFTC) to promulgate rules to define these terms, but we do not know the definitions that the CFTC will actually promulgate or how these definitions will apply to us.

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 Bakken of North Dakota and Montana. 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.

 

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Certain states in which we operate, including Texas 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 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, with initial results expected to be available by late 2012 and final results by 2014. 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. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

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, on July 28, 2011, the EPA issued proposed rules that would subject all 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. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business.

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.

 

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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 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 liquids 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 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.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

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

 

Item 3. Legal Proceedings

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

Panola Independent School District No. 4, Michael Kilpatrick, Gwen Grego, Carla Lessel, Thelma Christine Pate, Juanita Golightly, Melody Culberson and Charlotte Abernathy are the Plaintiffs in this case and are royalty owners in oil and gas drilling and spacing units for which the company’s exploration segment distributes royalty. The Plaintiffs’ central allegation is that the company’s exploration segment has underpaid royalty obligations by deducting post-production costs or marketing related fees. Plaintiffs also seek to pursue the case as a class action on behalf of persons who receive royalty from us for our Oklahoma production. We have asserted

 

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several defenses including that the deductions are permitted under Oklahoma law. We have also asserted that the case should not be tried as a class action due to the materially different circumstances that determine what, if any, deductions are taken for each lease. On December 16, 2009, the trial court entered its order certifying the class. We have appealed the trial court’s order. It is not currently known when the appeal will be acted on by the Oklahoma Appellate courts. Adjudication of the merits of the Plaintiffs’ claims is stayed until the appeal of the class certification order is decided.

 

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:

 

      2011      2010  

Quarter

   High      Low      High      Low  

First

   $ 62.47       $ 44.84       $ 51.00       $ 41.32   

Second

   $ 63.76       $ 51.58       $ 49.82       $ 36.37   

Third

   $ 62.66       $ 36.50       $ 42.76       $ 33.37   

Fourth

   $ 53.35       $ 33.58       $ 46.95       $ 35.37   

On February 10, 2012, the closing sale price of our common stock, as reported by the NYSE, was $47.03 per share. On that date, there were approximately 1,095 holders of record of our common stock.

We have never declared any cash dividends on our common stock and currently have no plans to do so. Any future determination by our board of directors to pay dividends on our common stock will be made only after considering our financial condition, results of operations, capital requirements and other relevant factors. Additionally, our bank credit agreement and the Notes prohibit the payment of cash dividends on our common stock under certain circumstances. For further information regarding our bank credit agreement and the Notes agreement’s impact on our ability to pay dividends see “Our Credit Agreement and Senior Subordinated Notes” under Item 7 of this report.

 

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

Set forth below is a line graph comparing our cumulative total shareholder return on our common stock with the cumulative total return of the S&P 500 Stock Index, S&P 600 Oil and Gas Exploration & Production and our peer group which includes Helmrich & Payne, Patterson – UTI Energy Inc. and Pioneer Drilling Co. 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.

 

LOGO

 

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Item 6. Selected Financial Data

The following table shows selected consolidated financial data. The data should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a review of 2011, 2010 and 2009 activity.

 

     As of and for the Year Ended December 31,  
     2011      2010      2009     2008     2007  
     (In thousands except per share amounts)  

Revenues

   $ 1,208,371       $ 881,845       $ 709,898      $ 1,358,093      $ 1,158,754   

Net income (loss)

   $ 195,867       $ 146,484       $ (55,500 )(1)    $ 143,625 (2)   $ 266,258   

Net income (loss) per common share:

            

Basic

   $ 4.11       $ 3.10       $ (1.18 )   $ 3.08      $ 5.74   

Diluted

   $ 4.08       $ 3.09       $ (1.18 )   $ 3.06      $ 5.71   

Total assets

   $ 3,256,720       $ 2,669,240       $ 2,228,399      $ 2,581,866      $ 2,199,819   

Long-term debt

   $ 300,000       $ 163,000       $ 30,000      $ 199,500      $ 120,600   

Other long-term liabilities

   $ 113,830       $ 92,389       $ 81,126      $ 75,807      $ 59,115   

Cash dividends per common share

   $ 0       $ 0       $ 0      $ 0      $ 0   

 

(1) 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.

 

(2) In December 2008, we incurred a non-cash ceiling test write down of our oil and natural gas properties of $282.0 million pre-tax ($175.5 million net of tax) due to low commodity prices at year-end.

 

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:

 

   

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.

 

   

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.

 

   

Mid-Stream – carried out by our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries. This segment buys, sells, gathers, processes and treats natural gas for third parties and for our own account.

Business Outlook

As discussed in other parts of this annual 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 natural gas, NGLs and oil production; the demand for oil 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.

 

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Our 2012 capital budget for all of our business segments forecasts a 6% increase over our 2011 capital expenditures, excluding acquisitions. Our oil and natural gas segment’s capital budget is $457 million, an 11% decrease over 2011, excluding acquisitions. We plan to continue our aggressive drilling program into 2012 with a significant portion of the wells being horizontal. Our drilling segment’s capital budget is $120.0 million, a 27% decrease over 2011. Our plans for 2012 include the construction of one new 1,500 horsepower diesel-electric drilling rig, as well as continuing to refurbish and upgrade several of our existing drilling rigs in our fleet in order that those rigs can be used in horizontal drilling operations. Our mid-stream segment’s capital budget is $224.0 million, a 182% increase over 2011. The increase is due to anticipated drilling activity by operators in the areas of our existing gathering systems resulting in new well connections as well as many new projects including new plants discussed further in the Executive Summary.

In developing our initial overall operating budget for 2012, we used average oil and natural gas prices of $90.00 per Bbl and $3.50 per Mcf. Our budget is subject to possible adjustments for various reasons including changes in commodity prices and industry conditions. Our 2012 operating budget will be funded using internally generated cash flow and borrowings under our credit agreement.

Executive Summary

Contract Drilling

The rate at which our drilling rigs were used (“our utilization rate”) for the fourth quarter 2011 was 65%, compared to 63% and 59% for the third quarter of 2011 and the fourth quarter of 2010, respectively.

Dayrates for the fourth quarter of 2011 averaged $19,330, a slight increase over the third quarter of 2011 and an increase of 17% over the fourth quarter of 2010. These increases were due primarily to increased demand for drilling rigs in the 1,000 to 1,500 horsepower range which are used in horizontal drilling and provide for higher rates.

Direct profit (contract drilling revenue less contract drilling operating expense) for the fourth quarter of 2011 increased 12% over the third quarter of 2011 and 41% over the fourth quarter of 2010. The increases were primarily due to increases in dayrates and utilization over the comparative periods as discussed above.

Operating cost per day for the fourth quarter of 2011 increased 5% over the third quarter of 2011 and increased 28% over the fourth quarter of 2010. The increases over the third quarter were primarily due to increases in rig servicing costs while the increases over the fourth quarter of 2010 are primarily due to increases in direct expenses due to pay increases for rig personnel and to a lesser extent from increases in rig servicing costs. As a result of competition to keep qualified labor, we anticipate compensation for rig personnel in certain regions to increase during the first quarter of 2012.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. However, with the current weakened natural gas market, operators are now focusing on drilling for oil and NGLs. Today, approximately 93% of our working drilling rigs are drilling for oil or NGLs. Of those, approximately 98% are drilling horizontal or directional wells.

At the end of 2010, we began constructing five new 1,500 horsepower, diesel-electric drilling rigs. All of these drilling rigs are now working in the Bakken shale in North Dakota under two-year drilling contracts.

During the third quarter of 2011, we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. These new build rigs will initially be working under three year contracts. One was placed into service during the fourth quarter of 2011 and the other will be placed into service during the first quarter of 2012.

 

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During the fourth quarter of 2011, we entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be used in North Dakota starting in the second quarter of 2012. This new build rig will initially be working under a three year contract. Subsequent to the 2011 year-end, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third party. Upon deployment of the new drilling rigs during the first and second quarters of 2012, this segment will have 128 drilling rigs in its fleet.

Our anticipated 2012 capital expenditures for this segment are $120.0 million, a 27% decrease over 2011.

As of December 31, 2011, we had 62 term drilling contracts with original terms ranging from six months to three years. Forty-six of these contracts are up for renewal in 2012, 16 in the first quarter, 11 in the second quarter, 13 in the third quarter and six in the fourth quarter and 16 are up for renewal in 2013 and later. These contracts include seven of the eight term contracts for the new drilling rigs discussed above. 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.

Oil and Natural Gas

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 in Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The net proved developed reserves associated with the acquisition are estimated at 6.6 Bcfe (91% natural gas) with production of 1.7 MMcfe per day. The acquisition also included in excess of 12,000 net held acres held by production for future development.

On August 31, 2011, we acquired certain producing oil and gas properties for $30.5 million in cash, subject to closing adjustments, 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 proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

During the fourth quarter of 2011, we leased approximately 60,000 net acres of undeveloped oil and gas leasehold located in south central Kansas for approximately $17.3 million.

Fourth quarter 2011 production from our oil and natural gas segment was 3,255,000 barrels of oil equivalent (Boe), a 4% increase over the third quarter of 2011 and a 21% increase over the fourth quarter of 2010. The increase in production came primarily from oil and NGL rich prospects where we completed and brought new wells online and, to a lesser extent, from production associated with the acquisitions discussed above. Due to low natural gas prices, we curtailed approximately 237 MMcf of our dry natural gas production in the month of December. The curtailed production was brought back on-line in January. Fourth quarter 2011 oil and NGL production was 42% of our total production compared to 34% of our total production over the fourth quarter of 2010. Our production in 2010 was hindered by delays in securing third party fracture stimulation services and delays associated with connecting wells to gathering systems. In addition, our 2010 production was curtailed because of the unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production.

Fourth quarter 2011 oil and natural gas revenues increased 4% over the third quarter of 2011 and increased 23% over the fourth quarter of 2010. These increases were primarily due to increased production and for the increase over the fourth quarter of 2010, also increased oil and NGL prices.

 

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Our oil prices for the fourth quarter of 2011 increased 2% over the third quarter of 2011 while NGL and natural gas prices decreased 4% and 7%, respectively. Our oil and NGL prices increased 19% and 8%, respectively, over the fourth quarter of 2010 while natural gas prices decreased 24%.

Direct profit (oil and natural gas revenues less oil and natural gas operating expense) decreased 3% from the third quarter of 2011 and increased 21% over the fourth quarter of 2010. The decrease over the third quarter 2011 was primarily attributable to decreases in gas production due to curtailment and decreases in gas and NGL prices. The increase over the fourth quarter 2010 was primarily attributable to increased production and from developmental drilling and acquisitions and increases in oil and NGL prices.

Operating cost per Boe produced for the fourth quarter of 2011 increased 21% over the third quarter of 2011 and increased 6% over the fourth quarter of 2010. The costs were lower in the third quarter of 2011 due to a gross production tax refund received for high cost gas tax credits, in addition, increases in the fourth quarter of 2011 were also due to increases in lease operating expenses (LOE) due to increased workover expense and higher saltwater disposal fees. The increase over the fourth quarter 2010 was primarily due to the increases in LOEs and an increase in production taxes. Production taxes increased due to commodity price increases between the periods and increased oil and NGL production.

For 2011, we hedged approximately 58% of our average daily oil production, approximately 66% of our average natural gas production and approximately 18% of our average natural gas liquids production (percentages based on our 2011 production) to help manage our cash flow and capital expenditure requirements.

Currently for 2012 we have hedged approximately 6,100 Bbls per day of oil production and approximately 50,000 Mmbtu per day of natural gas production. The oil production is hedged under swap contracts at an average price of $97.55 per barrel. The natural gas production is hedged under swap contracts at a comparable average NYMEX price of $5.09. The average basis differential for the applicable swaps is ($0.28). We have NGL hedges of 1,966 Bbls per day in the first quarter, 926 Bbls per day in the second quarter, 380 Bbls per day in the third quarter, and 380Bbls per day in the fourth quarter. The NGLs are hedged under swap contracts at an average price of $42.53 per barrel in the first quarter, $41.15 per barrel in the second quarter, $51.28 per barrel in the third quarter, and $50.28 per barrel in the fourth quarter.

Currently for 2013 we have hedged 3,000 Bbls per day of oil production. The oil production is hedged under swap contracts at an average price of $101.91 per barrel.

During 2011, we drilled 160 wells (82.42 net wells). Our 2012 production guidance is approximately 13.2 to 13.5 MMBoe, an increase of 9% to 12% over 2011, although actual results will continue to be subject to the timing of third party services, among other factors. For 2012, we plan to participate in the drilling of 160 wells and the level of our capital expenditures is $457.0 million.

Mid-Stream

Fourth quarter 2011 liquids sold per day increased 14% over the third quarter of 2011 and increased 76% over the fourth quarter of 2010. The increases were primarily the result of upgrades and expansions to existing plants and the connection of new wells. For the fourth quarter of 2011, gas processed per day increased 21% over the third quarter of 2011 and 84% over the fourth quarter of 2010. In 2010 and 2011, 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 2011, gas gathered per day increased 13% over the third quarter of 2011 and increased 37% over the fourth quarter of 2010 primarily from well connects throughout 2011.

NGL prices in the fourth quarter of 2011 decreased 10% from the price received in the third quarter of 2011 and 2% from the price received in the fourth quarter of 2010. The price of NGLs as compared to natural gas affects the revenue in our mid-stream operations and determines the fractionation spread which is the difference

 

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in the value received for the NGLs recovered from natural gas in comparison to the amount received for the equivalent MMBtu’s of natural gas if unprocessed.

Direct profit (mid-stream revenues less mid-stream operating expense) for the fourth quarter of 2011 increased 4% over the third quarter of 2011 and decreased 22% from the fourth quarter of 2010. The increase resulted primarily from increased liquids sold and gas processed volumes. The decrease over the fourth quarter of 2010 was primarily due to renegotiated contracts with customers at one of our processing plants whereby the contracts changed from POI to POP. Total operating cost for our mid-stream segment for the fourth quarter of 2011 increased 5% over the third quarter of 2011 and increased 87% over the fourth quarter of 2010 due primarily to the increase in gas purchased due to increased volumes.

Our Hemphill County facility in Texas is currently processing approximately 100 MMcf per day, after the addition of our fourth gas processing plant. Due to the continued high level of activity around the Hemphill facility, we will be installing an additional 45 MMcf per day gas processing plant which will increase this facility’s processing capacity to approximately 160 MMcf per day. This new plant should be completed during the second quarter of 2012.

At our Cashion facility, we are continuing to connect new wells to the system as well as installing a larger, more efficient gas processing plant. The installation of the new 25 MMcf per day high efficiency turbo-expander processing plant is scheduled to be operational during the second quarter of 2012.

We are also very active in the Mississippian play in north central Oklahoma. We completed construction of a new gathering system and gas processing plant in Grant County, Oklahoma during the fourth quarter of 2011. This system consists of approximately seven miles of gathering pipeline and a gas processing plant. Also in this area, we have begun construction of another gathering system and processing plant in Noble and Kay counties in Oklahoma. This system will initially consist of approximately 10 miles of 12” and 16” pipe with a 10 MMcf per day gas processing plant that will be upgraded to a 30 MMcf per day gas processing plant in the fourth quarter of 2012.

Along with the activities in the mid-continent area, we are continuing to expand operations in the Appalachian region. In the fourth quarter of 2011, we completed construction of a 16 mile, 16” pipeline and accompanying compressor station in Preston County, West Virginia. This system is currently flowing approximately 6 MMcf per day. In addition to the Preston County gathering system, we have begun construction of another gathering facility in Allegheny and Butler counties, Pennsylvania. The first phase of this project consists of approximately seven miles of gathering pipeline and a compressor station. The first well has been connected to this system and is currently flowing approximately 5 MMcf per day into a third party transmission line.

Our anticipated capital expenditures for 2012 are $224.0 million.

Critical Accounting Policies and Estimates

Summary

In this section, we identify those critical accounting policies we follow in preparing our financial statements and related disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. In the following discussion we will attempt to explain the nature of these estimates, assumptions and judgments, as well as the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.

 

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The following table lists the critical accounting policies, estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.

 

Accounting Policies

  

Estimates or Assumptions

  

Accounts Affected

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

  

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

•    Valuation of unproved properties

•    Estimates of future development costs

•    Derivatives measured at fair value

  

•    Oil and natural gas properties

•    Accumulated depletion, depreciation and amortization

•    Provision for depletion, depreciation and amortization

•    Impairment of oil and natural gas properties

•    Long-term debt and interest expense

     
     
     
     
     
     
     
     

Accounting for ARO for oil, NGLs and natural gas properties

  

•    Cost estimates related to the plugging and abandonment of wells

•    Timing of cost incurred

  

•    Oil and natural gas properties

•    Accumulated depletion, depreciation and amortization

•    Provision for depletion, depreciation and amortization

•    Current and non-current liabilities

•    Operating expense

Accounting for impairment of long-lived assets

  

•    Forecast of undiscounted estimated future net operating cash flows

  

•    Drilling and mid-stream property and equipment

•    Accumulated depletion, depreciation and amortization

•    Provision for depletion, depreciation and amortization

•    Other intangible assets

Goodwill

  

•    Forecast of discounted estimated future net operating cash flows

•    Terminal value

•    Weighted average cost of capital

  

•    Goodwill

Turnkey and footage drilling contracts

  

•    Estimates of costs to complete turnkey and footage contracts

  

•    Revenue and operating expense

•    Current assets and liabilities

Accounting for value of stock compensation awards

  

•    Estimates of stock volatility

•    Estimates of expected life of awards granted

•    Estimates of rates of forfeitures

  

•    Oil and natural gas properties

•    Shareholder’s equity

•    Operating expenses

•    General and administrative expenses

Accounting for derivative instruments and hedging

  

•    Derivatives measured at fair value

•    Derivatives measured for effectiveness and ineffectiveness

•    Non-qualifying derivatives measured at fair value

  

•    Current and non-current derivative assets and liabilities

•    Other comprehensive income as a component of equity

•    Oil and natural gas revenue

 

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Significant Estimates and Assumptions

Full Cost Method of Accounting for Oil, NGLs and Natural Gas Properties.    The determination of our oil, NGLs and natural gas reserves is a subjective process. It entails estimating underground accumulations of oil, NGLs and natural gas that cannot be measured in an exact manner. The degree of accuracy of these estimates depends on a number of factors, including, the quality and availability of geological and engineering data, the precision of the interpretations of that data, and individual judgments. Each year, we hire an independent petroleum engineering firm to audit our internal evaluation of our reserves. The wells or locations for which estimates of reserves were audited were those that comprised the top 82% of the total proved developed discounted future net income and 96% of the total proved undeveloped discounted future net income based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by us as of December 31, 2011. Included in Part I, Item 1 of this report are the qualifications of our independent petroleum engineering firm and the company’s personnel responsible for the preparation of our reserve reports.

As a general rule, the degree of accuracy of oil, NGLs and natural gas reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table:

 

Type of Reserves

  

Nature of Available Data

   Degree of Accuracy  

Proved undeveloped

   Data from offsetting wells, seismic data      Less accurate   
     

Proved developed non-producing

   The above as well as logs, core samples, well tests, pressure data      More accurate   
     

Proved developed producing

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

Assumptions as to future oil, NGLs and natural gas prices and operating and capital costs also play a significant role in estimating oil, NGLs and natural gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are influenced by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable oil, NGLs and natural gas reserves is greater than the projected revenues from the oil, NGLs and natural gas reserves). But more significantly, the estimated present value of the future cash flows from our oil, NGLs and natural gas reserves is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Companies using full cost accounting use the unweighted arithmetic average of the commodity prices existing on the first day of each of the 12 months before the end of the reporting period to calculate discounted future revenues, unless prices were otherwise determined under contractual arrangements. The average unescalated prices used in our reserve estimates were $96.19 per Bbl for oil, $61.78 per Bbl for NGLs and $4.12 per Mcf for natural gas, adjusted for price differentials.

We compute our provision for DD&A on a units-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for our producing properties:

 

   

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

 

   

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

Oil, NGLs and natural gas reserve estimates have a significant impact on our DD&A rate. If reserve estimates for a property or group of properties are revised downward in the future, the DD&A rate will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease. Based on our 2011 production level of 12.1 million barrels of oil equivalent (MMBoe), a 5% decline in the amount of our 2011 oil, NGLs and natural gas reserves would increase our DD&A rate by $0.84 per Boe and would decrease pre-tax income by $10.2 million annually. A 5% increase in the amount of our 2011 oil, NGLs and natural gas reserves would decrease our DD&A rate by $0.72 per Boe and would increase pre-tax income by $8.7 million annually.

 

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Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

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

The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil, NGLs and natural gas prices are depressed or if we have large downward revisions in our estimated proved oil, NGLs and natural gas reserves. Application of these rules during periods of relatively low oil or natural gas prices, even if temporary, increases the chance of a ceiling test write-down. Based on the 12-month 2011 average unescalated prices of $96.19 per barrel of oil, $61.78 per barrel of NGLs and $4.12 per Mcf of natural gas, adjusted for price differentials, for the estimated life of the respective properties, the unamortized cost of our oil and natural gas properties did not exceeded the ceiling of our proved oil, NGL and natural gas reserves.

Derivative instruments qualifying as cash flow hedges are to be included in the computation of limitation on capitalized costs. Our qualifying cash flow hedges used in the ceiling test determination at December 31, 2011, consisted of swaps covering 5.0 MMBoe in 2012 and 0.7 MMBoe in 2013. The effect of those hedges on the December 31, 2011 ceiling test was a $22.1 million pre-tax increase in the discounted net cash flows of our oil and natural gas properties. Even without the impact of those hedges, we would not have been required to take a write-down for the quarter. Our oil and natural gas hedging activities are discussed in Note 13 of our Notes to Consolidated Financial Statements.

We use the sales method for recording natural gas sales. This method allows for the recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. The expenses relating to the wells in which we have an imbalance are not material.

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

Accounting for Impairment of Long-Lived Assets.    Drilling equipment, transportation equipment, gas gathering and processing systems and other property and equipment are carried at cost less accumulated depreciation. Renewals and enhancements are capitalized while repairs and maintenance are expensed. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances suggest that these carrying amounts may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related

 

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to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. The estimate of fair value is based on the best information available, including prices for similar assets. Changes in these estimates could cause us to reduce the carrying value of property and equipment. An estimate of the impact to our earnings if other assumptions had been used is not practicable because of the significant number of assumptions that would be involved in the estimates. No significant impairments were recorded at December 31, 2011, 2010 or 2009.

Goodwill.    Goodwill represents the excess of the cost of acquisitions over the fair value of the net assets acquired. An annual impairment test is performed in the fourth quarter to determine whether the fair value has decreased and additionally when events indicate an impairment may have occurred. Goodwill is all related to our drilling segment, and accordingly, the impairment test is based on the estimated discounted future net cash flows of our drilling segment, utilizing discount rates and other factors in determining the fair value of our drilling segment. No goodwill impairment was recorded at December 31, 2011, 2010 or 2009.

Turnkey and Footage Drilling Contracts.    Because our contract drilling operations do not bear the risk of completion of a well being drilled under a “daywork” contract, we recognize revenues and expense generated under “daywork” contracts as the services are performed. Under “footage” and “turnkey” contracts we bear the risk of completion of the well, so revenues and expenses are recognized when the well is substantially completed. Substantial completion is determined when the well bore reaches the depth specified in the contract. The entire amount of a loss, if any, is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. The costs of drilling contracts uncompleted at the end of the reporting period (which includes expenses incurred to date on “footage” or “turnkey” contracts) are included in other current assets. In 2011, we did not drill any wells under turnkey or footage contracts. In 2010, we drilled four wells under a footage contract and none under a turnkey contract and in 2009, one under footage and none under turnkey.

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

Accounting for Derivative Instruments and Hedging.    We account for derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future oil, NGLs and natural gas production. We have hedged a portion of our anticipated production for the next 24 months. This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, we are required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain (loss) on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment must be recorded at fair value with gains (losses) recognized in earnings in the period of change.

 

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New Accounting Standards

Improving Disclosures about Fair Value Measurements.    In January 2010, the FASB issued ASU 2010-06 – Fair Value Measurements and Disclosures (ASC 820): Improving Disclosures about Fair Value Measurements, which provides additional guidance to improve disclosures regarding fair value measurements. The ASU amends ASC 820-10, Fair Value Measurements and Disclosures—Overall (formerly FAS 157, Fair Value Measurements) to add two new disclosures: (1) transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and (2) a gross presentation of activity within the Level 3 roll forward. The ASU also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The ASU applies to all entities required to make disclosures about recurring and nonrecurring fair value measurements. The effective date of the ASU was the first interim or annual reporting period beginning after December 15, 2009 and was adopted January 1, 2010, except for the gross presentation of the Level 3 roll forward information, which was adopted January 1, 2011. Because it only includes enhanced disclosures, this statement did not have a significant impact on us.

Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRS). In May 2011, the FASB issued ASU 2011-04 Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.    ASU 2011-4 is intended to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and IFRS. The amendments are of two types: (i) those that clarify the Board’s intent about the application of existing fair value measurement and disclosure requirements and (ii) those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The update is effective for annual periods beginning after December 15, 2011. We are in the process of evaluating the impact, if any, the adoption of this update will have on our financial statements.

Presentation of Comprehensive Income.    In June 2011, the FASB issued ASU 2011-05 – Presentation of Comprehensive Income. This ASU amends the Codification to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. The amendments to the Codification in the ASU do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.

ASU 2011-05 should be applied retrospectively. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We are in the process of evaluating the option we will choose to present comprehensive income and the impact it will have on our financial statements.

Testing Goodwill for Impairment.    In August 2011, the FASB issued ASU 2011-08 – Intangibles-Goodwill and Other (ASC 350): Testing Goodwill for Impairment. This ASU is intended to simplify how entities, both public and nonpublic, test goodwill for impairment. ASU 2011-08 permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC 350, Intangibles-Goodwill and Other. The more-likely-than-not threshold is defined as having a likelihood of more than 50%.

ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

 

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Financial Condition and Liquidity

Summary.

Our financial condition and liquidity depends on the cash flow from our operations and borrowings under our credit agreement. The principal factors determining the amount of our cash flow are:

 

   

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

 

   

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

 

   

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

 

   

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

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

 

     2011     2010     2009  
     (In thousands except percentages)  

Working capital

   $ 15,715      $ 41,052      $ 22,948   

Long-term debt

   $ 300,000      $ 163,000      $ 30,000   

Shareholders’ equity

   $ 1,947,017      $ 1,710,617      $ 1,565,810 (1) 

Ratio of long-term debt to total capitalization

     13     9     2 %(1) 

Net income (loss)

   $ 195,867      $ 146,484      $ (55,500 )(1) 

Net cash provided by operating activities

   $ 608,455      $ 390,072      $ 490,475   

Net cash used in investing activities

   $ (768,236   $ (536,261   $ (271,927

Net cash provided by (used in) financing activities

   $ 159,257      $ 146,408      $ (217,992

 

(1) 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. The write down impacted our 2009 shareholders’ equity, ratio of long-term debt to total capitalization and net income. There was no impact on our compliance with the covenants contained in our credit agreement.

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

 

     2011      2010      2009  

Contract Drilling:

        

Average number of our drilling rigs in use during the period

     76.1         61.4         38.9   

Total number of drilling rigs owned at the end of the period

     127         121         130   

Average dayrate

   $ 18,842       $ 15,478       $ 16,713   

Oil and Natural Gas:

        

Oil production (MBbls)

     2,511         1,521         1,286   

Natural gas liquids production (MBbls)

     2,239         1,549         1,488   

Natural gas production (MMcf)

     44,104         40,756         44,063   

Average oil price per barrel received

   $ 87.18       $ 69.52       $ 56.33   

Average oil price per barrel received excluding hedges

   $ 93.49       $ 76.65       $ 56.64   

Average NGL price per barrel received

   $ 43.64       $ 37.04       $ 22.81   

Average NGL price per barrel received excluding hedges

   $ 44.44       $ 36.96       $ 25.66   

Average natural gas price per mcf received

   $ 4.26       $ 5.62       $ 5.59   

Average natural gas price per mcf received excluding hedges

   $ 3.78       $ 4.05       $ 3.26   

Mid-Stream:

        

Gas gathered—MMBtu/day

     215,805         183,867         183,989   

Gas processed—MMBtu/day

     116,161         82,175         75,908   

Gas liquids sold—gallons/day

     412,064         271,360         243,492   

Number of natural gas gathering systems

     35         34         33   

Number of processing plants

     10         10         8   

 

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At December 31, 2011, we had unrestricted cash totaling $0.8 million and had borrowed $50.0 million of the $250.0 million we had elected to have currently available under our credit agreement. Our credit agreement is used primarily for working capital and capital expenditures.

On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of 6.625% Senior Subordinated Notes (the Notes) due 2021. The Notes were issued at par and mature on May 15, 2021. The net proceeds were used to repay outstanding borrowings under our credit agreement, which had approximately $220.3 million outstanding as of May 18, 2011. The remaining proceeds were used for general working capital purposes.

Working Capital

Typically, our working capital balance varies primarily because of the timing of our trade accounts receivable and accounts payable and from the fluctuation in current assets and liabilities associated with the mark to market value of our hedging activity. We had working capital of $15.7 million, $41.1 million and $22.9 million as of December 31, 2011, 2010 and 2009, respectively. The effect of our derivatives increased working capital by $18.0 million, $5.4 million and $4.7 million as of December 31, 2011, 2010 and 2009, respectively.

Contract Drilling

Many factors influence the number of drilling rigs we are working at any one time as well as the costs and revenues associated with that work. These factors include the demand for drilling rigs in our areas of operation, competition from other drilling contractors, the prevailing prices for oil, NGLs and natural gas, availability and cost of labor to run our drilling rigs and our ability to supply the equipment needed.

As activity has increased over last year’s levels, competition to keep qualified labor has also increased. In the third quarter 2010, we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana and again at the end of the first quarter of 2011 for drilling personnel in all our divisions. As a result of competition to keep qualified labor, we anticipate compensation for rig personnel in certain regions to increase during the first quarter of 2012.

Over the past year, as more of our customers shift to drilling horizontal wells, demand for drilling rigs in the 1,000 to 1,500 horsepower range has increased as those drilling rigs have the horsepower ideally suited for horizontal drilling. The future demand for and the availability of drilling rigs to meet that demand will have an impact on our future dayrates. For 2011, our average dayrate was $18,842 per day compared to $15,478 per day for 2010. Our average number of drilling rigs used in 2011 was 76.1 drilling rigs (61%) compared with 61.4 drilling rigs (50%) in 2010. Based on the average utilization of our drilling rigs during 2011, a $100 per day change in dayrates has a $7,610 per day ($2.8 million annualized) change in our pre-tax operating cash flow.

Our contract drilling segment provides drilling services for our exploration and production segment. Depending on their timing some of the drilling services performed on our properties are also deemed to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for such services are eliminated in our income statement, with any profit recognized as a reduction in our investment in our oil and natural gas properties. The contracts for these services are issued under the same conditions and rates as the contracts entered into with unrelated third parties. We eliminated revenue of $52.2 million, $40.1 million and $15.0 million for 2011, 2010 and 2009, respectively from our contract drilling segment and eliminated the associated operating expense of $32.6 million, $31.0 million and $13.7 million during 2011, 2010 and 2009, respectively, yielding $19.6 million, $9.1 million and $1.3 million during 2011, 2010 and 2009, respectively, as a reduction to the carrying value of our oil and natural gas properties.

 

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Impact of Prices for Our Oil, NGLs and Natural Gas

Any significant change in oil or natural gas prices has a material effect on our revenues, cash flow and the value of our oil, NGLs and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by worldwide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we cannot predict nor measure their future influence on the prices we will receive.

Based on our production in 2011, a $0.10 per Mcf change in what we are paid for our natural gas production, without the effect of hedging, would result in a corresponding $356,000 per month ($4.3 million annualized) change in our pre-tax operating cash flow. Our 2011 average natural gas price was $4.26 compared to an average natural gas price of $5.62 for 2010 and $5.59 for 2009. A $1.00 per barrel change in our oil price, without the effect of hedging, would have a $196,000 per month ($2.4 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGL prices, without the effect of hedging, would have a $175,000 per month ($2.1 million annualized) change in our pre-tax operating cash flow based on our production in 2011. Our 2011 average oil price per barrel was $87.18 compared with an average oil price of $69.52 in 2010 and $56.33 in 2009 and our 2011 average NGL price per barrel was $43.64 compared with an average liquids price of $37.04 in 2010 and $22.81 in 2009.

Because commodity prices have an effect on the value of our oil, NGLs and natural gas reserves, declines in those prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our credit agreement since that determination is based mainly on the value of our oil, NGLs and natural gas reserves. A reduction could limit our ability to carry out our planned capital projects.

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

Mid-Stream Operations

This segment is engaged primarily in the buying, selling, gathering, processing and treating of natural gas and operates three natural gas treatment plants, 10 processing plants, 35 gathering systems and 934 miles of pipeline. Our operations are located in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia. This segment enhances our ability to gather and market not only our own natural gas but also that owned by third parties and serves as a mechanism through which we can construct or acquire existing natural gas gathering and processing facilities. During 2011, 2010 and 2009 this segment purchased $71.5 million, $42.4 million and $29.3 million, respectively, of our natural gas production and natural gas liquids and provided gathering and transportation services of $4.6 million, $4.4 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.

Our mid-stream segment gathered an average of 215,805 MMBtu per day in 2011 compared to 183,867 MMBtu per day in 2010 and 183,989 MMBtu per day in 2009, processed an average of 116,161 MMBtu per day in 2011 compared to 82,175 MMBtu per day in 2010 and 75,908 MMBtu per day in 2009 and sold NGLs of 412,064 gallons per day in 2011 compared to 271,360 gallons per day in 2010 and 243,492 gallons per day in 2009. Volumes processed increased primarily due to the addition of wells connected and recent upgrades to several of our processing systems. Gas gathering volumes per day in 2011 increased 17% compared to 2010 primarily from wells connected to our systems throughout 2011. Processed volumes increased 41% over the comparative years and NGLs sold increased 52% over the comparative years primarily due to the addition of wells connected, recent upgrades to several of our processing systems and the doubling in size of our Hemphill facility in the Texas Panhandle.

 

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Our Credit Agreement and Senior Subordinated Notes

Credit Agreement.     On September 13, 2011, we entered into a Senior Credit Agreement (credit agreement) that replaced our previous credit agreement which was scheduled to mature on May 24, 2012. The credit agreement has a maturity date of September 13, 2016. The amount available to be borrowed is the lesser of the amount we elect as the commitment amount (currently $250.0 million) or the value of the borrowing base as determined by the lenders (currently $600.0 million), but in either event, not to exceed the maximum credit agreement amount of $750.0 million. We are charged a commitment fee ranging from 0.375 to 0.50 of 1% on the amount available but not borrowed. The rate varies based on the amount borrowed as a percentage of the amount of the total borrowing base. To date, in connection with this new credit agreement, we paid $1.8 million in origination, agency, syndication and other related fees. We are amortizing these fees over the life of the credit agreement. At both December 31, 2011 and February 10, 2012, borrowings were $50.0 million.

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

 

Lender

   Participation
Interest
 

BOK (BOKF, NA, dba Bank of Oklahoma)

     20.00

BBVA Compass Bank

     20.00

BMO

     16.80

Bank of America, N.A.

     16.80

Comerica Bank

     8.80

Crédit Agricole

     8.80

BNP Paribas

     8.80
  

 

 

 
     100.00
  

 

 

 

The amount of the borrowing base, which is subject to redetermination on April 1st and October 1st of each year, is based primarily on a percentage of the discounted future value of our oil and natural gas reserves. We or the lenders may request a onetime special redetermination of the amount of the borrowing base between each scheduled redetermination. In addition, we may request a redetermination following the completion of an acquisition that meets the requirements set forth in the credit agreement.

At our election, any part of the outstanding debt under the credit agreement may be fixed at a London Interbank Offered Rate (LIBOR). LIBOR interest is computed as the sum of the LIBOR base for the applicable term plus 1.75% to 2.50% depending on the level of debt as a percentage of the borrowing base and is payable at the end of each term, or every 90 days, whichever is less. Borrowings not under LIBOR bear interest at the Prime Rate, which cannot be less than LIBOR plus 1.00%, and is payable at the end of each month and the principal borrowed may be paid at any time, in part or in whole, without a premium or penalty. At December 31, 2011, all of our $50.0 million in outstanding borrowings were subject to LIBOR.

We used borrowings under the credit agreement to pay off the commitments issued under our previous credit agreement. In addition, we can use borrowings for financing general working capital requirements for (a) exploration, development, production and acquisition of oil and gas properties, (b) acquisitions and operation of mid-stream assets, (c) issuance of standby letters of credit, (d) contract drilling services, and (e) general corporate purposes of the Borrowers.

The credit agreement prohibits, among other things:

 

   

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

 

   

the incurrence of additional debt with certain limited exceptions; and

 

   

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

 

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

 

   

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

 

   

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

As of December 31, 2011, we were in compliance with the covenants contained in the credit agreement.

6.625% Senior Subordinated Notes.     On May 18, 2011, we completed the sale of $250.0 million aggregate principal amount of our 6.625% Senior Subordinated Notes due 2021 (the Notes). The Notes were issued at par and mature on May 15, 2021. We received net proceeds of approximately $244.0 million after deducting fees of approximately $6.0 million. Those fees are being amortized as deferred financing costs over the life of the Notes. We used the net proceeds to repay outstanding borrowings under our credit agreement, which was $220.3 million on May 18, 2011. The remaining proceeds were used for general working capital purposes. We also terminated two $15.0 million interest rate swaps associated with that debt with a settlement cost to us of $1.5 million.

The Notes are guaranteed by our wholly-owned domestic direct and indirect subsidiaries (the Guarantors). Unit, as the parent company, has no independent assets or operations. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. Any subsidiaries of Unit other than the Guarantors are minor. There are no significant restrictions on the ability of Unit to receive funds from its subsidiaries through dividends, loans, advances or otherwise.

The Notes were issued under an Indenture dated as of May 18, 2011, between us and Wilmington Trust FSB, as Trustee (the Trustee), as supplemented by the First Supplemental Indenture dated as of May 18, 2011, between us, the Guarantors and the Trustee, establishing the terms and providing for the issuance of the Notes (the Supplemental Indenture). The discussion of the Notes in this annual report is qualified by and subject to the actual terms of the Indenture and the First Supplemental Indenture.

The Notes bear interest at a rate of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year), and will mature on May 15, 2021.

On and after May 15, 2016, we may redeem all or, from time to time, a part of the Notes at certain redemption prices, plus accrued and unpaid interest. Before May 15, 2014, we may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the net cash proceeds of one or more equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, provided that at least 65% of the original principal amount of the Notes remains outstanding after each redemption. In addition, at any time before May 15, 2016, we may redeem the Notes, in whole or in part, at a redemption price equal to 100% of the principal amount plus a “make whole” premium, plus accrued and unpaid interest, if any, to the redemption date. If a “change of control” occurs, subject to certain conditions, we must offer to repurchase from each holder all or any part of that holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase. The Indenture and the Supplemental Indenture contain customary events of default. The Indenture governing the Notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to incur or guarantee additional indebtedness; pay dividends on our capital stock or redeem capital stock or subordinated indebtedness; transfer or sell assets; make investments; incur liens; enter into transactions with our affiliates; and merge or consolidate with other companies. We were in compliance with all covenants of the Notes as of December 31, 2011.

 

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Capital Requirements

Drilling Dispositions, Acquisitions and Capital Expenditures.     During 2009, we sold three mechanical drilling rigs (ranging in horsepower from 750 to 1,000) for $8.6 million and recorded a $4.8 million gain. In the third quarter 2009, we recognized an early termination fee associated with the cancellation of long-term contracts by a customer on two of eight rigs we postponed construction on in 2008. In addition, as a result of an existing contractual obligation, we took delivery of a new 1,500 horsepower drilling rig during the fourth quarter of 2009 at a cost of $13.2 million. The customer, who had signed a two year term contract for this rig when it was ordered, opted not to take delivery of the rig and paid an early termination fee under the contract provisions during the fourth quarter of 2009.

During the first half of 2010, we sold eight of our idle mechanical drilling rigs to an unaffiliated party. These drilling rigs ranged in horsepower from 800 to 1,000. Proceeds from this sale were $23.9 million resulting in a gain of $5.7 million which we recorded in the first quarter of 2010. The proceeds were used to refurbish and upgrade existing drilling rigs in our fleet allowing those drilling rigs to be used in horizontal drilling operations. We also placed into service in our Rocky Mountain division a 1,500 horsepower, diesel-electric drilling rig that previously had been placed on hold during 2009 by our customer.

In September 2010, we entered into a contract with an unaffiliated party under which we conveyed three of our idle mechanical drilling rigs and, in exchange, received a 1,200 horsepower electric drilling rig and $5.3 million. The three drilling rigs sold ranged in horsepower from 650 to 1,000. The transaction was closed in October and resulted in a gain of $3.5 million.

At the end of 2010, we began constructing five new 1,500 horsepower, diesel-electric drilling rigs. All of these drilling rigs are now working in the Bakken shale in North Dakota under two-year drilling contracts.

During the third quarter of 2011, we were awarded two additional new build rig contracts for 1,500 horsepower, diesel-electric drilling rigs. These new build rigs will initially be working under three year contracts. One was placed into service during the fourth quarter of 2011 and the other will be placed into service during the first quarter of 2012.

During the fourth quarter of 2011, we entered into an agreement to build a new 1,500 horsepower, diesel-electric drilling rig to be used in North Dakota starting in the second quarter of 2012. This new build rig will initially be working under a three year contract. Subsequent to the 2011 year-end, we sold an idle 600 horsepower mechanical drilling rig to an unaffiliated third party. Upon deployment of the new drilling rigs during the first and second quarters of 2012, this segment will have 128 drilling rigs in its fleet.

Our anticipated 2012 capital expenditures for this segment are $120.0 million. At December 31, 2011, we had commitments to purchase approximately $6.6 million for drill pipe, top drives and related equipment over the next twelve months. We have spent $162.2 million for capital expenditures during 2011 compared to $118.8 million in 2010 and $67.7 million in 2009.

Oil and Natural Gas Acquisitions and Capital Expenditures.    Most of our capital expenditures for this segment are discretionary and directed toward future growth. Our decision to increase our oil, NGLs and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We completed drilling 160 gross wells (82.42 net wells) in 2011 compared to 167 gross wells (87.52 net wells) in 2010 and 95 gross wells (42.51 net wells) in 2009. Our 2011 total capital expenditures for our oil and natural gas segment, excluding a $23.3 million ARO liability, and $50.0 million for acquisitions, totaled $506.7 million compared to 2010 capital expenditures of $361.4 million (excluding a $9.9 million ARO liability and $92.6 million for acquisitions) and 2009 capital expenditures of $226.0 million (excluding a $4.6 million

 

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ARO liability). Currently we plan to participate in drilling approximately 160 gross wells in 2012 and estimate our total capital expenditures (excluding any possible acquisitions) for our oil and natural gas segment will be approximately $457.0 million. Whether we are able to drill the full number of wells we are planning on drilling is dependent on a number of factors, many of which are beyond our control and include the availability of drilling rigs, availability of pressure pumping services, prices for oil, NGLs and natural gas, demand for oil and natural gas, the cost to drill wells, the weather and the efforts of outside industry partners.

During 2008 and 2009, we acquired interests in approximately 60,000 net undeveloped acres in the Marcellus Shale Play, located mainly in Pennsylvania and Maryland for approximately $43.6 million. In July 2009, we received $7.1 million and approximately 1,500 net undeveloped acres, representing payment for our 50% interest in 4,000 gross undeveloped acres and reimbursement for costs we paid on their behalf. On September 30, 2009, per our agreement with certain unaffiliated third parties, we were paid approximately $14.9 million for our 50% interest in approximately 18,000 gross undeveloped acres of the Marcellus Shale and $26.1 million for a receivable from the third parties for their 50% share of the costs we paid on their behalf to acquire the acreage. The sales proceeds reduced undeveloped leasehold and no gain or loss was recorded on this sale. We now have an interest in approximately 50,500 net undeveloped acres.

In June 2010, we completed an acquisition of oil and natural gas properties from certain unaffiliated parties. The properties were purchased for approximately $73.7 million in cash, after post closing adjustments. After these adjustments, the acquisition included approximately 45,000 net leasehold acres and 10 producing oil wells. This acquisition targeted the Marmaton horizontal oil play located mainly in Beaver County, Oklahoma. At the time of acquisition, proved developed producing net reserves associated with the 10 acquired producing wells was approximately 762,000 BOE—consisting of 511,000 barrels of oil, 155,000 barrels of NGLs and 573 MMcf of natural gas.

Also during the second quarter of 2010, we completed an acquisition consisting of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 million from an unaffiliated party.

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 in Oklahoma and Lipscomb County, Texas. The purchase price allocation was $8.4 million for proved properties and $3.9 million for acreage. The net proved developed reserves associated with the acquisition are estimated at 6.6 Bcfe (91% natural gas) with production of 1.7 MMcfe per day. 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, subject to closing adjustments, 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 proved reserves associated with the acquisition are approximately 31.2 Bcfe (99% natural gas), 83% of which is proved developed. The acquisition also included approximately 55,000 net acres of which 96% is held by production.

During the fourth quarter of 2011, we leased approximately 60,000 net acres of undeveloped oil and gas leasehold located in south central Kansas for approximately $17.3 million.

Mid-Stream Acquisitions and Capital Expenditures.    Our Hemphill County facility in Texas is currently processing approximately 100 MMcf per day, after the addition of our fourth gas processing plant, completed in the fourth quarter of 2010. Due to the continued high level of activity around the Hemphill facility, we will be installing an additional 45 MMcf per day gas processing plant which will increase this facility’s processing capacity to approximately 160 MMcf per day. This new plant should be completed during the second quarter of 2012.

 

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At our Cashion facility, we are continuing to connect new wells to the system as well as installing a larger, more efficient gas processing plant. The installation of the new 25 MMcf per day high efficiency turbo-expander processing plant is scheduled to be operational during the second quarter of 2012.

We are also very active in the Mississippian play in north central Oklahoma. We completed construction of a new gathering system and gas processing plant in Grant County, Oklahoma during the fourth quarter of 2011. This system consists of approximately seven miles of gathering pipeline and a gas processing plant. Also in this area, we have begun construction of another gathering system and processing plant in Noble and Kay counties in Oklahoma. This system will initially consist of approximately 10 miles of 12” and 16” pipe with a 10 MMcf per day gas processing plant that will be upgraded to a 30 MMcf per day gas processing plant in the fourth quarter of 2012.

Along with the activities in the mid-continent area, we are continuing to expand operations in the Appalachian region. In the fourth quarter of 2011, we completed construction of a 16 mile, 16” pipeline and accompanying compressor station in Preston County, West Virginia. This system is currently flowing approximately 6 MMcf per day. In addition to the Preston County gathering system, we have begun construction of another gathering facility in Allegheny and Butler counties, Pennsylvania. The first phase of this project consists of approximately seven miles of gathering pipeline and a compressor station. The first well has been connected to this system and is currently flowing approximately 5 MMcf per day into a third party transmission line.

During 2011, our mid-stream segment incurred $79.4 million in capital expenditures as compared to $29.8 million in 2010 and $9.9 million in 2009, including acquisitions. For 2012, we have budgeted capital expenditures of approximately $224.0 million.

Contractual Commitments

At December 31, 2011, we had the following contractual obligations:

 

     Payments Due by Period  
     Total      Less Than
1 Year
     2-3
Years
     4-5
Years
     After
5 Years
 
                
     (In thousands)  

Long-term debt (1)

   $ 461,570       $ 17,920       $ 35,839       $ 85,435       $ 322,376   

Operating leases (2)

     12,745         6,219         6,357         169         0   

Drill pipe, drilling components and equipment purchases (3)

     6,933         6,933         0         0         0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 481,248       $ 31,072       $ 42,196       $ 85,604       $ 322,376   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) See previous discussion in MD&A regarding our long-term debt. This obligation is presented in accordance with the terms of the Notes and credit agreement and includes interest calculated using our December 31, 2011 interest rates of 6.625% for the Notes and 2.7% for the credit agreement.

 

(2) We lease office space or yards in Elmwood, Elk City, Oklahoma City, Quinton and Tulsa, Oklahoma; Canadian and Houston, Texas; Denver and Englewood, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania under the terms of operating leases expiring through September, 2015. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

 

(3) We have committed to purchase approximately $6.6 million of new drilling rig components, drill pipe, drill collars and related equipment and $0.3 million remaining towards a gas treating plant over the next twelve months.

 

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At December 31, 2011, we also had the following commitments and contingencies that could create, increase or accelerate our liabilities:

 

      Estimated Amount of Commitment Expiration Per Period  

Other Commitments

   Total
Accrued
     Less
Than 1
Year
     2-3
Years
     4-5
Years
     After 5
Years
 
              
              
              
     (In thousands)  

Deferred compensation plan (1)

   $ 2,463         Unknown         Unknown         Unknown         Unknown   

Separation benefit plans (2)

   $ 6,845       $ 806         Unknown         Unknown         Unknown   

Derivative liabilities—commodity hedges

   $ 2,657       $ 2,657       $ 0       $ 0       $ 0   

ARO liability (3)

   $ 96,446       $ 3,040       $ 20,064       $ 4,517       $ 68,825   

Gas balancing liability (4)

   $ 3,263         Unknown         Unknown         Unknown         Unknown   

Repurchase obligations (5)

   $ 0         Unknown         Unknown         Unknown         Unknown   

Workers’ compensation liability (6)

   $ 17,026       $ 8,367       $ 3,006       $ 1,257       $ 4,396   

 

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

 

(2) Effective January 1, 1997, we adopted a separation benefit plan (“Separation Plan”). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to four weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive certain claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan (“Special Plan”). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant’s reaching the age of 65 or serving 20 years with the company. On December 31, 2008, all these plans were amended to bring the plans into compliance with Section 409A of the Internal Revenue Code of 1986, as amended.

 

(3) When a well is drilled or acquired, under “Accounting for Asset Retirement Obligations,” we record the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

 

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

 

(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the “Partnerships”) with certain qualified employees, officers and directors from 1984 through 2011, with a subsidiary of ours serving as general partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner’s interest at amounts to be determined by appraisal in the future. Repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $22,000 in 2011, $22,000 in 2010 and $1,000 in 2009.

 

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

 

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Derivative Activities

Periodically we enter into hedge transactions covering part of the interest rate payable under our credit agreement as well as the prices to be received for a portion of our oil, NGLs and natural gas production.

Interest Rate Swaps.     From time to time we enter into interest rate swaps to manage our exposure to possible future interest rate increases under our credit agreement. Under these transactions we swap the variable interest rate we would otherwise incur on a portion of our bank debt for a fixed rate of interest. In May 2011, in association with the repayment of outstanding borrowings under our credit agreement, we terminated our two outstanding interest rate swaps that were previously accounted for as cash flow hedges, resulting in an increase of approximately $1.5 million in interest expense. Approximately $1.1 million of that expense was capitalized and is being amortized over the life of the assets.

Commodity Hedges.     Our commodity hedging is intended to reduce our exposure to price volatility and manage price risks. Our decision on the type and quantity of our production and the price(s) of our hedge(s) is based, in part, on our view of current and future market conditions. Based on our 2011 average daily production, the approximated percentages of our production that we have hedged are as follows:

Oil and Natural Gas Segment:

 

     Q1’12     Q2’12     Q3’12     Q4’12     2013  

Daily oil production

     81     91     91     91     44

Daily natural gas production

     37     37     54     37     0

Natural gas liquids production

     32     15     6     6     0

With respect to the commodities subject to our hedges, the use of hedging limits the risk of adverse downward price movements, however it also limits increases in future revenues that would otherwise result from price movements above the hedged prices.

The use of derivative transactions carries with it the risk that the counterparties will not be able to meet their financial obligations under the transactions. Based on our evaluation at December 31, 2011, we determined that there was no material risk of non-performance by our counterparties. At December 31, 2011, the fair values of the net assets (liabilities) we had with each of the counterparties to our commodity derivative transactions are as follows:

 

     December 31,
2011
 
     (In millions)  

Bank of Montreal

   $             18.7   

Bank of America, N.A.

     6.5   

BNP Paribas

     6.1   

Comerica Bank

     1.4   

BBVA Compass Bank

     1.0   

BP Corporation

     0.2   

Crédit Agricole Corporate and Investment Bank, London Branch

     0.1   

Macquarie Bank

     (0.2
  

 

 

 

Total assets (liabilities)

   $ 33.8   
  

 

 

 

If a legal right of set-off exists, we net the value of the derivative arrangements we have with the same counterparty in our consolidated balance sheets. At December 31, 2011, we recorded the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $31.9 million and $4.5 million, respectively, and current derivative liabilities of $2.7 million. At December 31 2010, we recorded

 

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the fair value of our commodity derivatives on our balance sheet as current and non-current derivative assets of $5.6 million and $2.5 million, respectively, and current and non-current derivative liabilities of $13.3 million and $3.9 million, respectively.

We recognize in accumulated OCI the effective portion of any changes in fair value and reclassify the recognized gains (losses) on the sales to revenue and the purchases to expense as the underlying transactions are settled. As of December 31, 2011, we had a gain of $19.0 million, net of tax from our oil and natural gas segment derivatives in accumulated OCI.

Based on market prices at December 31, 2011, we expect to transfer to earnings a gain of approximately $18.0 million, net of tax, of the loss included in accumulated OCI during the next 12 months in the related month of production. The commodity derivative instruments existing as of December 31, 2011 are expected to mature by December 2013.

Certain derivatives do not qualify for designation as cash flow hedges. We had three basis swaps that did not qualify as cash flow hedges that expired in December 2011. For these derivatives, any changes in their fair value occurring before their maturity (i.e., temporary fluctuations in value) are reported in oil and natural gas revenues in our consolidated statements of operations. Changes in the fair value of derivatives designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in OCI until the hedged item is recognized into earnings. Any change in fair value resulting from ineffectiveness is recognized in our oil and natural gas revenues. The effect of these realized and unrealized gains and losses on our revenues and expenses were as follows at December 31:

 

     2011     2010      2009  
     (In thousands)  

Oil and natural gas revenue:

       

Realized gains on oil and natural gas derivatives

   $ 3,988      $ 53,473       $ 97,864   

Unrealized gains (losses) on ineffectiveness of cash flow hedges

     2,749        700         (897

Unrealized gains (losses) on non-qualifying oil and natural gas derivatives

     (336     336         (1,047
  

 

 

   

 

 

    

 

 

 

Impact on pre-tax earnings

   $ 6,401      $ 54,509       $ 95,920   
  

 

 

   

 

 

    

 

 

 

Stock and Incentive Compensation

During 2011, we granted awards covering 211,050 shares of restricted stock. These awards were granted as retention incentive awards. These stock awards had an estimated fair value as of the grant date of $10.8 million. Compensation expense will be recognized over their two and three year vesting periods, and during 2011, we recognized $4.1 million in additional compensation expense and capitalized $1.0 million for these awards. During 2010, we granted awards covering 450,355 shares of restricted stock. These awards were granted as retention incentive awards and are being recognized over their two and three year vesting periods. During 2009, we did not grant any awards of restricted stock. No SAR awards were made during 2011, 2010, or 2009.

During 2011, we recognized compensation expense of $10.0 million for all of our restricted stock, stock options and SAR grants and capitalized $2.5 million of compensation cost for oil and natural gas properties.

Insurance

We are self-insured for certain losses relating to workers’ compensation, control of well and employee medical benefits. Insured policies for other coverage contain deductibles or retentions per occurrence that range from $50,000 to $1.5 million. We have purchased stop-loss coverage in order to limit, to the extent feasible, per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage will adequately protect us against liability from all potential consequences. We have elected to use an ERISA governed occupational injury benefit plan to cover all Texas drilling operations in lieu of covering them under Texas Workers’ Compensation. If insurance coverage becomes more expensive, we may choose to self-insure, decrease our limits, raise our deductibles or any combination of these rather than pay higher premiums.

 

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Oil and Natural Gas Limited Partnerships and Other Entity Relationships.

We are the general partner of 16 oil and natural gas partnerships which were formed privately or publicly. Each partnership’s revenues and costs are shared under formulas set out in that partnership’s agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party’s share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party’s behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party’s level of activity and are considered by us to be reasonable. During 2011, 2010 and 2009, the total we received for all of these fees was $1.4 million, $1.5 million and $1.1 million, respectively. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements.

Effects of Inflation

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

Off-Balance Sheet Arrangements

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

 

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Results of Operations

2011 versus 2010

Following is a comparison of selected operating and financial data:

 

     2011     2010     Percent
Change (1)
 

Total revenue

   $ 1,208,371,000      $ 881,845,000        37

Net income

   $ 195,867,000      $ 146,484,000        34

Contract Drilling:

      

Revenue

   $ 484,651,000      $ 316,384,000        53

Operating costs excluding depreciation

   $ 269,899,000      $ 186,813,000        44

Percentage of revenue from daywork contracts

     100     100     0

Average number of drilling rigs in use

     76.1        61.4        24

Average dayrate on daywork contracts

   $ 18,842      $ 15,478        22

Depreciation

   $ 79,667,000      $ 69,970,000        14

Oil and Natural Gas:

      

Revenue

   $ 516,316,000      $ 400,807,000        29

Operating costs excluding depreciation, depletion and amortization

   $ 131,271,000      $ 105,365,000        25

Average oil price (Bbl)

   $ 87.18      $ 69.52        25

Average NGL price (Bbl)

   $ 43.64      $ 37.04        18

Average natural gas price (Mcf)

   $ 4.26      $ 5.62        (24)

Oil production (Bbl)

     2,511,000        1,521,000        65

NGL production (Bbl)

     2,239,000        1,549,000        45

Natural gas production (Mcf)

     44,104,000        40,756,000        8

Depreciation, depletion and amortization rate (Boe)

   $ 15.06      $ 11.94        26

Depreciation, depletion and amortization

   $ 183,350,000      $ 118,793,000        54

Mid-Stream Operations:

      

Revenue

   $ 208,238,000      $ 154,516,000        35

Operating costs excluding depreciation and amortization

   $ 174,859,000      $ 122,146,000        43

Depreciation and amortization

   $ 16,101,000      $ 15,385,000        5

Gas gathered—MMBtu/day

     215,805        183,867        17

Gas processed—MMBtu/day

     116,161        82,175        41

Gas liquids sold—gallons/day

     412,064        271,360        52

General and administrative expense

   $ 30,055,000      $ 26,152,000        15

Interest expense, net

   $ 4,167,000      $ 0        NM   

Income tax expense

   $ 123,135,000      $ 90,737,000        36

Average interest rate

     5.6     3.5     60

Average long-term debt outstanding

   $ 249,681,000      $ 94,873,000        163

 

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

Contract Drilling

Drilling revenues increased $168.3 million or 53% in 2011 versus 2010 primarily due to a 24% increase in the average number of drilling rigs in use during 2011 compared to 2010 and a 22% higher average dayrate in 2011 compared to 2010. Average drilling rig utilization increased from 61.4 drilling rigs in 2010 to 76.1 drilling rigs in 2011. Oil and NGL prices improved in 2011 compared to 2010, creating increased demand for drilling rigs.

 

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Drilling operating costs increased $83.1 million or 44% between the comparative years of 2011 and 2010 primarily due to increased utilization and increased direct cost due to higher personnel cost. Due to an increase in activity over last year’s levels, competition to keep qualified labor has increased. Starting in the third quarter 2010, we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana and again at the end of the first quarter 2011 for drilling personnel in all divisions. Contract drilling depreciation increased $9.7 million or 14% primarily due to increased utilization and from capital expenditures associated with the construction of new drilling rigs and for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $115.5 million or 29% in 2011 as compared to 2010 primarily due to an increase in equivalent production volumes of 23% and an increase in oil and NGL prices partially offset by decreases in prices for natural gas. Average oil and NGL prices between the comparative years increased 25% to $87.18 per barrel and 18% to $43.64 per barrel, respectively, while natural gas prices decreased 24% to $4.26 per Mcf. In 2011, as compared to 2010, oil production increased 65%, NGL production increased 45% and natural gas production increased 8%. Production increased from our drilling program and from wells acquired over the last twelve months while gas production for 2010 was negatively impacted by an unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production and production growth was hampered by the lack of availability of fracing services to complete wells.

Oil and natural gas operating costs increased $25.9 million or 25% between the comparative years of 2011 and 2010 due to increases in lease operating expenses due to increased well servicing costs and higher saltwater disposal fees and higher gross production taxes due to higher oil prices and revenue from increased production between years partially offset by refunds of production taxes attributable to high-cost gas wells received during the third quarter of 2011. Lease operating expenses per Boe increased 1% to $6.79.

Depreciation, depletion and amortization (“DD&A”) increased $64.6 million or 54% primarily due to a 26% increase in our DD&A rate and a 23% increase in equivalent production. The increase in our DD&A rate in 2011 compared to 2010 resulted primarily from increased net book value from new reserves added throughout 2010 and 2011. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Mid-Stream

Our mid-stream revenues increased $53.7 million or 35% in 2011 as compared to 2010 primarily due to higher NGL volumes and prices. The average price for NGLs sold increased 12%. Gas processing volumes per day increased 41% between the comparative years and NGLs sold per day increased 52% between the comparative periods. The increase in volumes processed per day is primarily attributable to the volumes added from new wells connected to existing systems and increased capacity of processing facilities. NGLs sold volumes per day increased due to an increase in volumes processed, upgrades to several of our processing facilities and the doubling in size of our Hemphill facility in the Texas Panhandle. Gas gathering volumes per day increased 17% primarily from new well connections.

Operating costs increased $52.7 million or 43% in 2011 compared to 2010 primarily due to a 11% increase in prices paid for natural gas purchased and a 38% increase in gas purchased. Depreciation and amortization increased $0.7 million, or 5%. For 2011, we increased well connections over 2010 due to increased drilling activity by operators in the areas of our existing gathering systems along with the benefit of the additional processing capacity from the Hemphill facility completed during the fourth quarter of 2010.

Other

General and administrative expenses increased $3.9 million or 15% in 2011 compared to 2010 primarily due to increases in employee costs.

 

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Interest expense, net of capitalized interest, increased $4.2 million between the comparative years of 2011 and 2010. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate increased by 60% primarily due to the issuance of $250.0 million of Senior Subordinated Notes during the second quarter of 2011 and our average debt outstanding was $154.8 million higher in 2011 as compared to 2010 due to the drilling of developmental wells and construction of new rigs in 2011.

Income tax expense increased $32.4 million or 36% in 2011 compared to 2010 primarily due to increased income. Our effective tax rate was 38.6% for 2011 and 38.3% for 2010. Current income tax benefit for 2011 was $2.4 million due to a larger than expected net operating loss carryback recognized in the third quarter of 2011 compared with $9.9 million of total current income tax benefit for 2010 due to expected bonus depreciation for 2010. We paid $0.7 million in income taxes during 2011.

 

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2010 versus 2009

Following is a comparison of selected operating and financial data:

 

     2010     2009     Percent
Change (1)
 

Total revenue

   $ 881,845,000      $ 709,898,000        24

Net income (loss)

   $ 146,484,000      $ (55,500,000 )     NM   

Contract Drilling:

      

Revenue

   $ 316,384,000      $ 236,315,000        34

Operating costs excluding depreciation

   $ 186,813,000      $ 140,080,000        33

Percentage of revenue from daywork contracts

     100     100     0

Average number of drilling rigs in use

     61.4        38.9        58

Average dayrate on daywork contracts

   $ 15,478      $ 16,713        (7 )% 

Depreciation

   $ 69,970,000      $ 45,326,000        54

Oil and Natural Gas:

      

Revenue

   $ 400,807,000      $ 357,879,000        12

Operating costs excluding depreciation, depletion, amortization and impairment

   $ 105,365,000      $ 87,734,000        20

Average oil price (Bbl)

   $ 69.52      $ 56.33        23

Average NGL price (Bbl)

   $ 37.04      $ 22.81        62

Average natural gas price (Mcf)

   $ 5.62      $ 5.59        1

Oil production (Bbl)

     1,521,000        1,286,000        18

NGL production (Bbl)

     1,549,000        1,488,000        4

Natural gas production (Mcf)

     40,756,000        44,063,000        (8 )% 

Depreciation, depletion and amortization rate (Boe)

   $ 11.94      $ 11.22        6

Depreciation, depletion and amortization

   $ 118,793,000      $ 114,681,000        4

Impairment of oil and natural gas properties

   $ 0      $ 281,241,000        NM   

Mid-Stream Operations:

      

Revenue

   $ 154,516,000      $ 108,628,000        42

Operating costs excluding depreciation and amortization

   $ 122,146,000      $ 87,908,000        39

Depreciation and amortization

   $ 15,385,000      $ 16,104,000        (4 )% 

Gas gathered—MMBtu/day

     183,867        183,989        0

Gas processed—MMBtu/day

     82,175        75,908        8

Gas liquids sold—gallons/day

     271,360        243,492        11

General and administrative expense

   $ 26,152,000      $ 24,011,000        9

Interest expense, net

   $ 0      $ 539,000        NM   

Income tax expense (benefit)

   $ 90,737,000      $ (32,226,000     NM   

Average interest rate

     3.5     4.0     (13 )% 

Average long-term debt outstanding

   $ 94,873,000      $ 111,808,000        (15 )% 

 

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

Contract Drilling:

Drilling revenues increased $80.1 million or 34% in 2010 versus 2009 primarily due to a 58% increase in the average number of rigs in use during 2010 compared to 2009 and increased mobilization revenue offset by a 7% lower average dayrate. Average drilling rig utilization increased from 38.9 drilling rigs in 2009 to 61.4 drilling rigs in 2010 as commodity prices improved in 2010 compared to 2009, creating increased demand for drilling rigs.

 

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Drilling operating costs increased $46.7 million or 33% between the comparative years of 2010 and 2009 primarily due to increases in the number of drilling rigs used and increases in general and administrative expenses somewhat offset by decreases in worker’s compensation. During 2009, competition to keep and attract qualified employees to meet our requirements did not materially affect us due to the depressed conditions within our industry. Due to an increase in activity over 2009 levels, competition to keep qualified labor has increased in 2010. In the third quarter 2010, we increased compensation for drilling personnel in Oklahoma, Texas and Louisiana. Contract drilling depreciation increased $24.6 million or 54% primarily due to an increase in the number of drilling rigs being utilized and an increase in capital expenditures for upgrades to existing drilling rigs in our fleet.

Oil and Natural Gas

Oil and natural gas revenues increased $42.9 million or 12% in 2010 as compared to 2009 primarily due to an increase in average oil, NGL and natural gas prices partially offset by a 3% decrease in equivalent production volumes. Average oil prices between the comparative years increased 23% to $69.52 per barrel, NGL prices increased 62% to $37.04 per barrel and natural gas prices increased 1% to $5.62 per Mcf. In 2010, as compared to 2009, oil production increased 18%, NGL production increased by 4% and natural gas production decreased 8%. Production for 2010 was negatively impacted by an unexpected shut-in of some of our production from operational issues experienced at a third party facility that processes our Segno field production while production growth was hampered primarily during the first nine months of the year by the lack of availability of fracing services to complete wells.

Oil and natural gas operating costs increased $17.6 million or 20% between the comparative years of 2010 and 2009 due primarily to higher gross production taxes due to increased oil and natural gas sales revenue between the periods. Production taxes in 2009 were also reduced by $5.8 million for production tax credits attributable to high-cost gas wells.

DD&A increased $4.1 million or 4% primarily due to a 6% increase in our DD&A rate slightly offset by a 3% decrease in equivalent production. The 2009 DD&A rate was lower after a $281.2 million pre-tax non-cash ceiling test write-down of the carrying value of our oil and natural gas properties at the end of the first quarter in 2009 as a result of a decline in commodity prices and the DD&A rate increases throughout 2010 from increased net book value on new reserves added. Our DD&A expense on our oil and natural gas properties is calculated each quarter utilizing period end reserve quantities adjusted for current period production.

Mid-Stream

Our mid-stream revenues increased $45.9 million or 42% for 2010 as compared to 2009 primarily due to higher NGL and natural gas prices and higher NGL volumes processed and sold. The average price for NGLs sold increased 31% and the average price for natural gas sold increased 28%. Gas processing volumes per day increased 8% between the comparative periods and NGLs sold per day increased 11% between the comparative periods. The increase in volumes processed per day is primarily attributable to the volumes added from new wells connected to existing systems throughout 2010. NGLs sold volumes per day increased due to both an increase in volumes processed and upgrades to several of our processing facilities. Gas gathering volumes per day remained flat.

Operating costs increased $34.2 million or 39% in 2010 compared to 2009 primarily due to a 36% increase in prices paid for natural gas purchased and a 9% increase in purchased volumes. Depreciation and amortization decreased $0.7 million, or 4%, primarily due to decreased amortization on our intangible assets.

Other

Other revenue of $10.1 million for 2010 was primarily attributable to the sale of eight mechanical drilling rigs and the sale of a gas pipeline in which we owned a 60% interest, partially offset by a $2.5 million loss associated with the write-off of progress payments made on a gas plant contract that was terminated.

 

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General and administrative expenses increased $2.1 million or 9% compared to 2009 primarily due to increases in employee costs.

Interest expense, net of capitalized interest, decreased $0.5 million between the comparative years. We capitalized interest based on the net book value associated with undeveloped leasehold not being amortized, the construction of additional drilling rigs and the construction of gas gathering systems. Our average interest rate decreased by 13% and our average debt outstanding was 15% lower in 2010 as compared to 2009. Total interest expense was increased $1.2 million for 2010 and $1.0 million for 2009 from interest rate swap settlements.

Income tax expense (benefit) changed from a benefit of $32.2 million in 2009 to an expense of $90.7 million in 2010 due to the non-cash ceiling test write-down of $281.2 million pre-tax ($175.1 million, net of tax) of our oil and natural gas properties during the quarter ended March 31, 2009, which was more than offset by improved performance of our operating segments. Our effective tax rate was 38.3% and 36.7% for 2010 and 2009, respectively. The portion of our taxes reflected as a current income tax benefit for 2010 was $9.9 million as compared to a benefit of $0.2 million in 2009. Income taxes paid in 2010 were $3.1 million.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk.     Our major market risk exposure is in the prices we receive for our oil, NGLs and natural gas production. Those prices are primarily driven by the prevailing worldwide price for crude oil and market prices applicable to our natural gas production. Historically, these prices have fluctuated and we expect they will continue to do so. The price of oil, NGLs and natural gas also affects both the demand for our drilling rigs and the amount we can charge for the use of our drilling rigs. Based on our 2011 production, a $0.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $356,000 per month ($4.3 million annualized) change in our pre-tax cash flow. A $1.00 per barrel change in our oil price would have a $196,000 per month ($2.4 million annualized) change in our pre-tax operating cash flow and a $1.00 per barrel change in our NGLs prices would have a $175,000 per month ($2.1 million annualized) change in our pre-tax cash flow.

We use hedging transactions to manage the risk associated with price volatility. Our decisions regarding the amount and prices at which we choose to hedge certain of our products is based, in part, on our view of current and future market conditions. The transactions we use include financial price swaps under which we will receive a fixed price for our production and pay a variable market price to the contract counterparty. We do not hold or issue derivative instruments for speculative trading purposes.

 

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Oil and Natural Gas Segment:

At December 31, 2011, the following cash flow hedges were outstanding:

 

Term

   Commodity   Hedged Volume    Weighted Average Fixed
Price for Swaps
   Hedged Market  

Jan’12 – Dec’12

   Crude oil – swap   5,250 Bbl/day    $96.54      WTI – NYMEX   

Jan’13 – Dec’13

   Crude oil – swap   2,000 Bbl/day    $102.05      WTI – NYMEX   

Jan’12 – Dec’12

   Natural gas – swap   30,000 MMBtu/day    $5.05      IF – NYMEX (HH)   

Jan’12 – Dec’12

   Natural gas – swap   15,000 MMBtu/day    $5.62      IF – PEPL   

Jan’12 – Mar’12

   Liquids –  swap(1)   1,350,014 Gal/mo    $1.10      OPIS – Conway   

Jan’12 – Mar’12

   Liquids –  swap(1)   1,155,018 Gal/mo    $0.91      OPIS – Mont Belvieu   

Apr’12 – Dec’12

   Liquids –  swap(2)   180,006 Gal/mo    $2.11      OPIS –  Conway   

Apr’12 – Jun’12

   Liquids –  swap(3)   1,000,028 Gal/mo    $0.78      OPIS – Mont Belvieu   

Jul’12 – Dec’12

   Liquids –  swap(4)   310,000 Gal/mo    $0.69      OPIS – Mont Belvieu   

 

(1) Types of liquids involved are natural gasoline, ethane, propane, isobutane and normal butane.
(2) Types of liquids involved are natural gasoline.
(3) Types of liquids involved are natural gasoline and ethane.
(4) Types of liquids involved are ethane.

Subsequent to December 31, 2011, the following cash flow hedges were entered into:

 

Term

  

Commodity

  

Hedged Volume

   Weighted Average Fixed
Price for Swaps
  

Hedged Market

Mar’12 – Dec’12

   Crude oil – swap    1,000 Bbl/day    $103.90    WTI – NYMEX

Jan’13 – Dec’13

   Crude oil – swap    1,000 Bbl/day    $101.63    WTI – NYMEX

Jul’12 – Sep’12

   Natural gas – swap    20,000 MMBtu/day    $2.98    IF – NYMEX (HH)

Interest Rate Risk.     Our interest rate exposure relates to our long-term debt under our credit agreement and the Notes. The credit agreement, at our election bears interest at variable rates based on the Prime Rate or the LIBOR Rate. At our election, borrowings under our credit agreement may be fixed at the LIBOR Rate for periods of up to 180 days. Under our Notes, we pay a fixed rate of interest of 6.625% per year (payable semi-annually in arrears on May 15 and November 15 of each year).

 

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Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

Unit Corporation and Subsidiaries

 

     Page  

Management’s Report on Internal Control over Financial Reporting

     74   

Consolidated Financial Statements:

  

Report of Independent Registered Public Accounting Firm

     75   

Consolidated Balance Sheets at December 31, 2011 and 2010

     76   

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

     77   

Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December  31, 2009, 2010 and 2011

     78   

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

     79   

Notes to Consolidated Financial Statements

     80   

 

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Management’s Report on Internal Control over Financial Reporting

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

 

   

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

 

   

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

 

   

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

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

The company’s management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2011. In making this assessment, the company’s management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on their assessment, the company’s management concluded that, as of December 31, 2011, the company’s internal control over financial reporting was effective based on those criteria.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

 

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