UNIT CORP - Annual Report: 2010 (Form 10-K)

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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, 2010

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)

(Registrant’s telephone number, including area code) (918) 493-7700

Securities registered pursuant to Section 12(b) of the Act:

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.

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, 2010, 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, 2010) held by non-affiliates was approximately $1,002,853,599. 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.

DOCUMENTS INCORPORATED BY REFERENCE

Exhibit Index—See Page 120

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FORM 10-K

UNIT CORPORATION

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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.

BOKF – Bank of Oklahoma Financial Corporation.

Btu – British thermal unit, used in terms of 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.

CEGT – Center Point Energy Gas Transmission

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.

MMBtu – Million Btu’s.

MMcf – Million cubic feet of natural gas.

MMcfe – Million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of crude oil or NGLs to six Mcf of natural gas.

Net acres or net wells – The sum of the fractional working interests owned in gross acres or gross wells.

NGLs – Natural gas liquids.

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DEFINITIONS – (Continued)

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.

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.

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UNIT CORPORATION

Annual Report

For The Year Ended December 31, 2010

PART I

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, Unit Corporation and/or one or more of its subsidiaries.

Our executive offices are at 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136; our telephone number is (918) 493-7700. In addition to our executive offices, we have offices or yards in Beaver, Elk City, Oklahoma City, Oklahoma; Canadian, Houston and Humble, Texas; Englewood and Denver, Colorado; Pinedale, Wyoming; and Pittsburgh, Pennsylvania.

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. Our operations are generally conducted through our three principal wholly owned subsidiaries:

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

The following table provides certain information about us as of February 11, 2011:

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2010 SEGMENT OPERATION HIGHLIGHTS

Contract Drilling

Oil and Natural Gas

Mid-Stream

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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 land contract drilling operations:

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 2010, 79 of our 121 available 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 11, 2011:

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. In 2010, as drilling activity in the Barnett Shale in North Texas picked up, we reactivated our North Texas division. Currently our operating divisions consist of the following: Arkoma, Gulf Coast, Mid-continent, North Texas, Panhandle, Rocky Mountain and Woodward.

2010 brought a dramatic increase in our drilling rig utilization. In the middle of 2009 our active rig count bottomed out at 28 rigs. Our active rig count at the start of 2010 was 42 rigs and utilization continued to climb to 72 active rigs to finish out 2010.

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 2010, our Mid-Continent and Woodward divisions averaged 17.4 and five drilling rigs operating during 2010, respectively. Part of the increased activity in this area stems from the oil and NGL interest by operators working in the Cana Woodford and Granite Wash horizontal plays.

Panhandle of Texas. During 2010, we averaged 5.7 drilling rigs operating in this division. We remain the largest drilling contractor in the combined Anadarko Basin of Oklahoma and the Texas Panhandle in terms of total rig count.

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 2010, our Arkoma division averaged 3.5 drilling rigs operating. The Arkoma Basin has traditionally been a natural gas play. With lower natural gas commodity prices during 2010 and operators shifting their drilling emphasis to liquids, we moved two rigs from this division to our Mid-Continent and Texas Panhandle divisions for greater utilization.

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

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and unconventional gas plays of northwest Louisiana, East Texas and South Texas. The Gulf Coast division averaged 13.6 drilling rigs operating for the year. The Haynesville Shale play was an active area for us with six rigs working there during most of 2010. In 2010, as a result of operators searching for oil and NGL’s, a new market emerged in the Eagle Ford Shale in South Texas. We had five rigs in the Eagle Ford at year end 2010.

North Texas Barnett Shale.    North Central Texas is the home of the Barnett Shale, a tight gas bearing formation. It is touted as one of the largest natural gas fields in the U.S., and as being one of the first unconventional shale gas formations to have been unlocked by technological advances in the use of multi-stage high pressure fracturization completion processes.

Three rigs secured contracts to begin operations in the Barnett Shale in the first quarter of 2010 and ran throughout the year.

Rocky Mountains.    The Rocky Mountain area 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 13.4 drilling rigs during 2010. We have drilling rigs operating in the Pinedale Anticline of western Wyoming, the Niobrara in southeast Wyoming, the Bakken Shale in Montana and North Dakota, as well as other areas throughout this expansive geographical area. With greater emphasis by our customers for oil prospects, in 2010 we repositioned several of our rigs to the Bakken Shale in North Dakota. We closed out 2010 with eight drilling rigs working in the Bakken Shale, including one new 1,500 horsepower drilling rig which began operations during the second quarter of 2010. As mentioned earlier, we are in the process of building five new 1,500 horsepower electric drilling rigs with skidding systems that will be deployed throughout 2011 to the Bakken Shale.

At any given time our ability to use all of our drilling rigs 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. In late 2008, our utilization rate was significantly affected by the U.S. and world economic downturn. For the first nine months of 2008 our average utilization rate was 81%, by December 2008, our average utilization rate had declined to 61%. For 2009, our average utilization rate declined to 30% and for 2010, our average utilization rate increased to 50%.

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

Drilling Rig Fleet.    The following table summarizes the 2010 changes made to our drilling rig fleet. A more complete discussion of these changes follows the table:

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Dispositions, Acquisitions, and Construction.    During the first quarter 2009, we sold one 750 horsepower mechanical drilling rig for $3.1 million and recorded a $0.9 million gain. During the third quarter 2009, we sold a 1,000 horsepower mechanical drilling rig for $2.8 million and recorded a $1.9 million gain. During the fourth quarter 2009, we sold a 1,000 horsepower mechanical drilling rig for $2.7 million and recorded a $2.0 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 horse power 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 additional 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.

Recently we signed two year contracts for each of the five new 1,500 horse power drilling rigs which will be deployed in the Bakken play. We are currently building these rigs, two of which will be delivered during the first quarter of 2011 and the remaining three during the third quarter of 2011.

Historically, our contract drilling segment has experienced a greater demand for natural gas drilling as opposed to drilling for oil and NGLs. Today, with the weakened demand and price for natural gas, operators are primarily focusing on drilling for oil and NGLs. Approximately 73% of our drilling rigs working today are drilling for oil or NGLs and approximately 88% 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 termination by the customer on short notice and on 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 drilled four wells under a footage contract in 2010, one well in 2009 and none in 2008. 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. To date, we have not experienced significant losses in performing turnkey contracts. We did not have any turnkey contracts 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.

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

Customers.    During 2010, QEP Resources, Inc. was our largest drilling customer accounting for approximately 28% 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 were considered to be material. No other third party customer accounted for 10% or more of our contract drilling revenues. During 2010, 2009 and 2008, we drilled 75, 38 and 122 wells, respectively, or 13%, 9% and 12%, respectively, of our total wells drilled for our oil and natural gas segment.

Our contract drilling segment also provides drilling services for our oil and natural gas segment. Depending on the timing of the drilling services performed on our properties those services may be deemed, for financial reporting purposes, to be associated with the acquisition of an ownership interest in the property. Revenues and expenses for 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 $40.1 million, $15.0 million and $65.5 million during 2010, 2009 and 2008, respectively from our contract drilling segment and eliminated the associated operating expense of $31.0 million, $13.7 and $37.6 million during 2010, 2009 and 2008, respectively, yielding $9.1 million, $1.3 million and $27.9 million during 2010, 2009 and 2008, 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 as a means of diversifying our drilling operations. 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, Colorado and Pennsylvania and, to a lesser extent, in Arkansas, New Mexico, Wyoming, Montana, Alabama, Kansas, Mississippi, Michigan, Maryland 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, 2010:

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As of December 31, 2010, we did not have any material water floods, pressure maintenance operations, nor any other material operations that were in process.

Description and Location of Our Core Operations

West division.    Our Segno play, located primarily in Polk, Tyler and Hardin Counties, Texas, continues to grow as the company expanded its prospect area to the south by entering into a joint exploration agreement with a third party for the use of a proprietary 3-D seismic survey covering approximately 151 square miles. Under the exploration agreement, we were required to drill three Wilcox wells, which we did during 2010. One of the wells resulted in a confirmed gas discovery that started selling gas in late November at an initial rate of approximately 151 Bbls of oil per day, 310 Bbls of NGLs per day, and 3.7 MMcf per day, or an equivalent rate of approximately 6.4 MMcfe per day. The other two wells are potential gas discoveries pending further testing after the pipeline connecting the wells is finished, which should occur in late first quarter 2011. For 2010, we operated and completed 22 wells at an average working interest of 62.5% and a 77% success rate. The overall production from our Segno area for December 2010 averaged 1,141 Bbls of oil per day, 1,371 Bbls of NGLs per day and 16.6 MMcf per day, or an equivalent rate of 31.7 MMcfe per day. The average completed gross well cost was approximately $3.4 million per well for 2010 wells. For 2011, we plan to drill approximately 20 gross wells with an approximate working interest of 80% for an estimated cost of $54 million. We own approximately 57,000 gross and 48,000 net acres in the Segno play.

In the Bakken play located in North Dakota, we participated in 20 wells in 2010 with a 100% success rate at an average working interest of 11% and a total cost of approximately $18.5 million. The finding cost for the 2010 wells averaged $21.24 per barrel of oil equivalent (BOE) with a total per well cost of approximately $7.9 million, which equates to gross reserves of approximately 500,000 BOE per well. For 2011, we anticipate participating in approximately 25 gross wells with an average working interest of 15% at a total cost of approximately $30 million. We own approximately 12,750 net acres in the play and anticipate two to three rigs drilling on its North Dakota Bakken leasehold during 2011.

East division.    In Shelby County, Texas, a second horizontal Haynesville well, the KC GU #1H (59% WI) has drilled 4,000 feet of Haynesville lateral. The well was successfully fracture stimulated in late January 2011 and we anticipate first gas sales by the end of February 2011. We expect to drill one to three horizontal Haynesville wells in Shelby County. In Harrison County, Texas, the Double K #1H (33% WI) had first gas sales in late September from the Cotton Valley sand at initial rates of approximately 8.8 MMcf per day and 127 Bbls of oil per day with 2,120 pounds flowing tubing pressure. The lateral length was 4,000 feet and the well was fracture stimulated in 10 stages and 2.3 million pounds of sand. An offset is currently drilling and we anticipate participating in one to two additional wells in 2011.

In the Marcellus play located in Somerset County, Pennsylvania, there were no new wells drilled in 2010 and we don’t plan on drilling any new wells in 2011. The current plan is to delay drilling activity until the gas prices improve.

Central division.    During 2010 in our Marmaton horizontal oil play located in Beaver County, Oklahoma, we drilled 19 horizontal Marmaton wells with an average working interest of 92% and participated in one outside operated horizontal Marmaton well with a 50% working interest. Completion of many of these wells was delayed until the beginning of the fourth quarter due to the unavailability of third party fracturing services. Early in the fourth quarter, we were able to obtain the needed fracturing services and by year end 2010, had successfully fracture stimulated 11 of the 20 wells, and subsequently had first oil sales on 10 of these wells in late 2010. The initial 30-day average production rate for the 10 wells ranged from 80 BOE per day to 480 BOE per day with an average rate of 230 BOE per day. The average ultimate recovery for each of the 10 completed wells is estimated to be 130,000 BOE at an average completed well cost of approximately $2.8 million. The current cost to drill and complete new wells is estimated at $2.5 million. We have secured frac dates for 2011, which should catch up the wells waiting to be fracture stimulated as well as the new wells that will be drilled. For 2011, we anticipate

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running a two drilling rig program in this play that should result in 30 to 35 gross wells at an approximate net cost of $52 million. We currently have leases on approximately 60,000 net acres in this play.

In our Granite Wash (GW) play located in the Texas Panhandle, we drilled and operated 12 horizontal wells with an average working interest of 73% and four vertical wells with an average working interest of 87%. In addition, we participated in 10 outside operated GW horizontal wells, with an average working interest of approximately 12%, located in the Texas Panhandle and Western Oklahoma. Focusing on the operated horizontal wells, 10 of the 12 completed wells had first oil and gas sales during 2010, consisting of one well in each of the first three quarters and seven wells during the fourth quarter. The GW laterals completed in 2010 include three GW “A”, six GW “B”, one GW “C1” and two GW “F” zones. In 2009, we also completed a well in the GW “C”. This brings the total GW zones that have been successfully completed on our leasehold to five and the plan is to test a sixth zone in the GW “D” zone in 2011. Highlights from the completed 2010 wells include an 83% working interest in a GW “B” zone completion with an initial daily peak rate of 1,135 Bbls of oil per day, 662 Bbls of NGLs per day and 6.2 MMcf per day or an equivalent daily rate of approximately 17 MMcfe per day and a 30 day average daily rate of 14.3 MMcfe per day. The first GW “F” zone completion (100% working interest) had a peak daily rate of 329 Bbls of oil per day, 366 Bbls of NGLs per day, and 3.4 MMcf per day, or an equivalent rate of approximately 7.6 MMcfe per day and a 30 day average rate of 5.8 MMcfe per day. The average daily peak rate for the 2010 completed wells was approximately 8.0 MMcfe per day with oil and liquids accounting for approximately 50% of the production stream at a completed well cost of approximately $5.1 million. We expect to work three to four Unit drilling rigs drilling Granite Wash horizontal wells in 2011 which equates to approximately 22 operated GW wells at an approximate net cost of $82 million. In addition, we anticipate we will participate in approximately 16 outside operated horizontal wells at an approximate net cost of $14 million.

Dispositions and Acquisitions.    There were no material dispositions during 2010 or 2009. 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 due from those 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 third parties for approximately $73.7 million in cash. The properties purchased included approximately 45,000 net leasehold acres and 10 producing oil wells and focused on the Marmaton horizontal oil play located mainly in Beaver County, Oklahoma. Proved developed producing net reserves associated with the 10 acquired producing wells is 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 of approximately 32,000 net acres of undeveloped oil and gas leasehold located in Southwest Oklahoma and North Texas for approximately $17.6 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:

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As of February 11, 2011, we had participated in 14 gross (10.13 net) wells started during 2011.

Cost incurred for development drilling includes $84.6 million, $24.5 million and $89.4 million in 2010, 2009 and 2008, respectively, to develop booked proved undeveloped oil and natural gas reserves.

The following table summarizes our leasehold acreage at December 31, 2010:

The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United States for the years 2011—2015, as disclosed in our December 31, 2010 oil and natural gas reserve report, are $102.6 million, $107.7 million, $25.4 million, $20.1 million and $5.6 million, respectively.

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Price and Production Data.    The following table identifies the average sales price, oil, NGLs and natural gas production volumes and average production cost per equivalent Mcf for our oil, NGLs and natural gas production for the years indicated:

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Our Mendota field is the only field that contains greater than 15% or more of our total proved reserves expressed on an oil equivalent barrels basis.

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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: