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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

OR

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:

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) 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.  ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes  x    No  ¨

Aggregate Market Value of the Voting Stock Held By

Non-affiliates on June 30, 2004 – $1,262,168,792

Number of Shares of Common Stock

Outstanding on March 7, 2005 – 45,838,644

DOCUMENTS INCORPORATED BY REFERENCE

1. Portions of Registrant’s Proxy Statement with respect to the Annual Meeting of Stockholders to be held May 4, 2005, to be filed subsequently—Part III.

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FORM 10-K

UNIT CORPORATION

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UNIT CORPORATION

Annual Report

For The Year Ended December 31, 2004

PART I

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 in Houston, Humble, Borger, Booker and Midland, Texas; Casper, Wyoming; Oklahoma City and Woodward, Oklahoma; and Denver, Colorado.

The following table provides certain information regarding us as of March 1, 2005:

Our primary Internet address is www.unitcorp.com. We make our periodic SEC Reports (Forms 10-Q and Forms 10-K) and current reports (Form 8-K) available free of charge through our Web site as soon as reasonably practicable after they are filed electronically with the SEC. In addition, we post on our Web site copies of the various corporate governance documents that we have adopted. We may from time to time provide important disclosures to investors by posting them in the investor relations section of our Web site, as allowed by SEC rules.

Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 450 Fifth Street, 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 Web site at www.sec.gov that contains reports, proxy and information statements, and other information regarding our company that we file electronically with the SEC.

When used in this report, 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.

Item 1.    Business and Item 2.    Properties

OUR BUSINESS

We were founded in 1963 as a contract drilling company. Today, through our three principal wholly owned subsidiaries, Unit Drilling Company, Unit Petroleum Company and Superior Pipeline Company, L.L.C., we

At various times, and from time to time, each of these three principal subsidiaries may conduct their operations through subsidiaries of their own.

OUR LAND CONTRACT DRILLING BUSINESS

General.    Our wholly owned subsidiary, Unit Drilling Company, drills onshore natural gas and oil wells for our own account as well as for a wide range of other oil and gas companies. Its operations are mainly located in the Oklahoma and Texas areas of the Anadarko and Arkoma Basins, the Texas Gulf Coast and in the East Texas and Rocky Mountain regions.

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

Description and location of our Drilling Rigs.    A land drilling rig consists, in part, of engines, drawworks or hoists, derrick or mast, substructure, pumps to circulate the drilling fluid, blowout preventers and drill pipe. Over the life of a typical drilling rig, due to the normal wear and tear of operating 24 hours a day, several of the major components, such as engines, mud pumps and drill pipe, must be replaced or rebuilt on a periodic basis. Other components, such as 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 large air compressors, trucks and other support equipment.

Our drilling rigs have maximum depth capacities ranging from 5,000 to 40,000 feet.

The following table shows the distribution of our drilling rigs as of March 1, 2005:

At present, we do not have a shortage of drilling rig related equipment. However, at any given time, our ability to use all of our drilling rigs is dependent on a number of conditions, including the availability of qualified labor, drilling supplies and equipment as well as demand. As demand for our drilling rigs improved through 2004, it became increasingly difficult to find additional qualified labor to work on our drilling rigs. If demand for our drilling rigs remains at its current level or increases, we expect competition for qualified labor to continue which will result in higher operating costs.

Acquisitions.    On July 30, 2004, we completed our acquisition of Sauer Drilling Company, a Casper, Wyoming-based drilling company. We paid $40.3 million in this acquisition which included $5.3 million for working capital. This acquisition included nine drilling rigs, a fleet of trucks, and an equipment and repair yard with associated inventory located in Casper, Wyoming. The drilling rigs range from 500 horsepower to 1,000 horsepower with depth capacities rated from 5,000 feet to 16,000 feet. The fleet of trucks consists of four vacuum trucks, and 11 rig-up trucks which are used to move the drilling rigs to new locations. We also use the trucks to move other drilling contractors’ drilling rigs. This acquisition increased our share of the drilling rig market in the

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Rocky Mountains in the medium-to-smaller drilling rig depth ranges. The equipment yard will continue to provide service space for the nine newly acquired drilling rigs and trucks as well as for our other drilling rigs located in our Rocky Mountain Division.

On May 4, 2004, we acquired two drilling rigs and related equipment for $5.5 million. These drilling rigs are rated at 850 and 1,000 horsepower, respectively, with depth capacities from 12,000 to 15,000 feet. We refurbished the drilling rigs for approximately $4.0 million. One drilling rig was placed into service at the beginning of August 2004 and the other drilling rig was placed into service in the middle of September 2004. Both of these drilling rigs are working in our Rocky Mountain Division.

With these two acquisitions and the completion of construction of another 1,500 horsepower diesel electric drilling rig in June 2004, our total drilling rig fleet at December 31, 2004 was 100 drilling rigs.

On January 5, 2005, we acquired a subsidiary of Strata Drilling L.L.C. for $10.5 million. In this acquisition we acquired two drilling rigs as well as spare parts, inventory, drill pipe, and other major drilling rig components. These two drilling rigs are both 1,500 horsepower, diesel electric drilling rigs with the capacity to drill 12,000 to 20,000 feet. One drilling rig is currently operating and the other will require approximately $2.0 million in expenditures to complete. This latter drilling rig should be fully operational within 90 days. Both of these drilling rigs will ultimately be moved into our Rocky Mountain Division.

Also in January 2005, we completed the construction of a 1,500 horsepower diesel electric drilling rig which began operating in the Anadarko Basin. The addition of this drilling rig, when combined with the two we obtained in our acquisition from Strata Drilling L.L.C., brings our total drilling rig fleet to 103 drilling rigs as of March 1, 2005.

We plan to initiate construction of our 104th drilling rig in the first quarter of 2005. This drilling rig will be a 1,500 horsepower diesel electric drilling rig and is scheduled to be added to our Rocky Mountain Division.

Types of Drilling Contracts We Use.    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 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. 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. To date, we have not experienced significant losses in performing turnkey contracts. In 2004, we did not drill any turnkey wells while in 2003 we drilled six turnkey wells, and turnkey revenue represented 1% of our 2003 contract drilling revenues. Because market conditions as well as the desires of our customers determine the use of turnkey contracts, we can’t predict whether the portion of drilling conducted on a turnkey basis will increase in the future.

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Customers.    During 2004, 10 customers accounted for approximately 44% of our contract drilling revenues. Chesapeake Operating, Inc. was our largest customer providing 11% of our total contract drilling revenues. Thirty-five of the wells we drilled in 2004 were operated by our exploration and production subsidiary. These latter wells also have working interests which are owned by limited partnerships for which we act as general partner. As required by the SEC, the profit received by our contract drilling subsidiary when we drill wells for our exploration and production subsidiary, which amounted to $3.7 million and $1.9 million during 2004 and 2003, respectively, was used to reduce the carrying value of our oil and natural gas properties rather than being included in our operating profit.

Additional Information.    Further information relating to our contract drilling operations can be found in Notes 1, 2, 10 and 12 of the Notes to Consolidated Financial Statements in Item 8 of this report.

OUR OIL AND NATURAL GAS BUSINESS

General.    In 1979 we began to develop our exploration and production operations to diversify our contract drilling revenues. Today, our wholly owned subsidiary, Unit Petroleum Company, conducts our exploration and production activities. Until it was merged into Unit Petroleum Company on March 3, 2005, we also conducted operations through our subsidiary PetroCorp Incorporated. Our producing oil and natural gas properties, undeveloped leaseholds and related assets are mainly in Oklahoma, Texas, Louisiana and New Mexico and, to a lesser extent, in Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Kansas, Mississippi, Michigan and Canada.

The following table presents certain information regarding our oil and gas operations as of December 31, 2004:

When we are the operator of a property, we generally use drilling rigs owned by our subsidiary Unit Drilling Company.

Acquisition.    On January 30, 2004, we acquired the outstanding common stock of PetroCorp Incorporated for $182.1 million in cash. PetroCorp explored and developed oil and natural gas properties primarily in Texas and Oklahoma. Approximately 84% of the oil and natural gas properties acquired in this acquisition are located in the Mid-Continent and Permian basins, while 6% are located in the Rocky Mountains and 10% are located in the Gulf Coast Basin. The acquired properties increased our oil and natural gas reserve base by approximately 56.7 billion equivalent cubic feet of natural gas and provide additional locations for our future development drilling.

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Well and Leasehold Data.    The tables below identify certain information regarding our oil and natural gas exploratory and development drilling operations:

As of March 1, 2005, we have participated in the drilling of 25 gross (7.3 net) wells during 2005.

Cost incurred for development drilling includes $16.0 million, $20.4 million and $10.8 million in 2004, 2003 and 2002, respectively, to develop booked proved undeveloped oil and natural gas reserves.

The following table summarizes our oil and natural gas leasehold acreage for each of the years indicated:

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The future estimated development costs necessary to develop our proved undeveloped oil and natural gas reserves in the United States for the years 2005, 2006 and 2007, as disclosed in our December 31, 2004 oil and natural gas reserve report are $42.5 million, $31.3 million and $7.9 million, respectively. No future development costs have been estimated for Canada.

Price and Production Data.    The following table identifies the average sales price, oil and natural gas production volumes and average production cost per equivalent Mcf [1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas] for our oil and natural gas production for the years indicated:

Oil and Natural Gas Reserves.    The following table identifies our estimated proved developed and undeveloped oil and natural gas reserves for each of the years indicated:

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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. Most of these contracts contain provisions for readjustment of price, termination and other terms customary in the industry.

Additional Information.    Further information relating to our oil and natural gas operations can be found in Notes 1, 2, 10 and Supplemental Information of the Notes to Consolidated Financial Statements in Item 8 of this report.

OUR NATURAL GAS GATHERING AND PROCESSING BUSINESS

General.    In July 2004, we consolidated and increased our natural gas gathering and processing business when we acquired the 60% of Superior Pipeline Company L.L.C. that we did not already own. We paid $19.8 million in this acquisition. Before July 2004, we owned 18 gathering systems which we have now consolidated with Superior’s systems. Superior is a mid-stream company engaged primarily in the purchasing, gathering, processing and treating of natural gas and operates one natural gas treatment plant, owns three processing plants, 32 active gathering systems and 440 miles of pipeline. Superior operates in Oklahoma, Texas and Louisiana. It has been in business since 1996. This acquisition and consolidation will increase our ability to gather and market our natural gas (as well as third party natural gas) and construct or acquire existing natural gas gathering and processing facilities. Before this acquisition, our 40% interest in the income or loss from operations of Superior was shown as equity in earnings of unconsolidated investments.

The following table presents certain information regarding our natural gas gathering and processing operations:

Additional Information.    Further information relating to our natural gas gathering and processing operations can be found in Notes 1, 2 and 10 of the Notes to Consolidated Financial Statements in Item 8 of this report.

VOLATILE NATURE OF OUR BUSINESS

The prevailing prices for natural gas and oil significantly affect our revenues, operating results, cash flow and future rate of growth. Because natural gas makes up the biggest part of our oil and natural gas reserves, as well as the focus of most of the contract drilling work we do for others, changes in natural gas prices have a larger impact on us than changes in oil prices. Historically, oil and natural gas prices have been volatile, and we expect them to continue to be so. The following table shows the highest and lowest average monthly natural gas and oil price we received, by quarter, for each of the periods indicated:

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Prices for oil 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:

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

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. We started to experience less demand for our drilling rigs starting in October, 2001 as natural gas prices began to fall in early 2001. The rates received for our drilling rigs also began to fall until they reached a low of $7,275 per day in February of 2003. As natural gas and oil prices once again began to rise during the second quarter of 2003 and have remained at higher levels throughout 2004, both demand for our drilling rigs and dayrates have steadily increased. In December 2004, the average dayrate of the 100 drilling rigs that we owned was $9,786 per day. Since short-term and long-term trends in oil and natural gas prices affect the demand for our drilling rigs, future demand and dayrates received for our drilling services is uncertain.

Our natural gas gathering and processing operations provide us greater flexibility in delivering our (and other parties) natural gas from the wellhead to major natural gas pipelines. Margins received for the delivery of this natural gas is dependent on the price for natural gas and the demand for natural gas in our area of operations. If the price of natural gas liquids falls without a corresponding decrease in the cost of natural gas, it may become uneconomical to extract certain natural gas liquids. The volumes of natural gas processed is highly dependent on the volume and Btu content of the natural gas gathered.

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COMPETITION

All of our businesses are highly competitive and price sensitive. Competition in onshore contract drilling traditionally involves factors as price, efficiency, condition of equipment, availability of labor and equipment, reputation and customer relations. Some of our onshore contract drilling competitors are substantially larger than we are and have greater financial and other resources than we do.

Our oil and natural gas operations likewise encounter strong competition from other oil 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 natural gas gathering and processing operations compete 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, build gathering systems in production fields and deliver the natural gas once the gathering systems are established. The principal elements of competition include the rates, terms 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 11 oil and gas limited partnerships. Four of these partnerships were formed for investment by third parties and seven (the employee partnerships) were formed to allow our employees and directors to participate with Unit Petroleum Company in its operations. The partnerships formed for use in connection with third party investments were formed in 1984, 1985 and 1986. One employee partnership has been formed each year beginning with 1984.

The employee partnerships formed in 1984 through 1990 were consolidated into a single consolidating partnership in 1993 and the employee partnerships formed in 1991 through 1999 were also consolidated into the consolidating partnership in 2002. The consolidation of the 1991 through the 1999 employee partnerships was done by the general partner under the terms of the respective partnership agreements and did not involve any vote, consent or approval by the limited partners. The employee partnerships each have a set annual percentage (ranging from 1% to 15%) of our interest in most of the oil and natural gas wells we drill or acquire for our own account during the 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.

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 1 and 7 to the Consolidated Financial Statements in Item 8 of this report.

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EMPLOYEES

As of March 1, 2005, we had approximately 2,339 employees in our land contract drilling operations, 113 employees in our oil and natural gas operations, 21 employees in our gas gathering and processing operations and 42 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.

OPERATING AND OTHER RISKS

Our contract drilling operations are subject to the many hazards inherent in the drilling industry. These include injury or death to personnel, well 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 operations and gas gathering and processing operations are also subject to many of these 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, our drilling contracts provide for the division of responsibilities between us and our customers, and we seek to obtain indemnification from our drilling customers for some of these risks. When we use our own drilling rigs to drill oil and natural gas wells for our own account, the contractual indemnification provisions would not act to shift responsibility or liability to a third party. To the extent that we are unable to transfer these risks to our drilling customers, we seek protection through insurance. However, our insurance or our indemnification agreements, if any, may not adequately protect us against liability from the consequences of the hazards described above. In addition, even if we have insurance coverage, we may still have a degree of exposure based on the amount of our deductible or retention. 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 to us. In addition, we may not be able to obtain insurance 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.

Exploration and development operations involve numerous risks that can and do result in dry holes, the failure to be able to produce oil and natural gas in commercial quantities and the inability to fully produce discovered oil or natural gas reserves. The cost of drilling, completing and operating wells is substantial and uncertain. Our operations may also be curtailed, delayed or cancelled as a result of many things beyond our control, including:

A majority of the wells in which we own an interest are operated by other parties. As a result, we have little control over the operations of those wells and this lack of control can act to increase our risk. Operators of these wells may act in ways that are not in our best interests.

Our future performance depends on our ability to find or acquire additional oil and natural gas reserves that are economically recoverable. In general, production from oil and natural gas properties declines as oil and natural gas reserves deplete, with the rate of decline depending on the reservoir characteristics of each producing

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well. Unless we successfully replace the oil and natural gas reserves that we produce, our oil and natural gas reserves will decline, resulting eventually in a decrease in our oil and natural gas production, revenues and cash flow from operations. Historically, we have succeeded in increasing oil and natural gas reserves after taking production into account. However, we may not be able to continue to replace our oil and natural gas reserves in a manner consistent with our past history. Low prices of oil and natural gas also limit the kinds of oil and natural gas reserves that we can economically develop. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

Our natural gas gathering and processing operations involve numerous risks that may result in the failure to recover our cost in the natural gas gathering and processing facilities. The cost of developing the gathering systems and processing plants is substantial and uncertain. Our operations may be curtailed, delayed or cancelled as a result of many things beyond our control, including:

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.

GOVERNMENTAL REGULATIONS

Various state and federal regulations affect the production and sale of oil and natural gas. All states in which we conduct activities impose 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 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

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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 individual pipeline restructuring proceedings of the early to mid-1990s, the 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 intrastate commerce.

More recently, the 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.

As a result of these changes, 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. 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.

In the past, Congress has been very active in the area of natural gas regulation. However, 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 are not regulated and are at market prices. The price received from the sale of these products will be affected by the cost of transporting the 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 may 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. We are not able to predict with certainty what effect, if any, these relatively new federal regulations or the periodic review of the index by the FERC will have on us.

Federal, state, and local agencies 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

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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.

SAFE HARBOR STATEMENT

This report, including information included in, or incorporated by reference from, future filings by us with the SEC, as well as information contained in written material, press releases and oral statements issued by or on our behalf, contain, or may contain, certain statements that are “forward-looking statements” within the meaning of federal securities laws. All statements, other than statements of historical facts, included or incorporated by reference in this report, which address 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.

These forward-looking statements include, among others, such things as:

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

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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:

You should not place undue reliance on any of these forward-looking statements. 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 provide 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 certain factors that in the future could cause our consolidated results for 2005 and beyond to differ materially from those that may be presented in any such forward-looking statement made by or on behalf of us.

Commodity Prices.    The prices we receive for our oil and natural gas production have a direct impact on our revenues, profitability and our cash flow as well as our ability to meet our projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond our control, including:

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 both natural gas and oil are becoming more and more influenced by trading on the commodities markets which, at times, has tended to increase the volatility associated with these prices resulting, at times, in large differences in such prices even on a week-to-week and month-to-month basis. All of these factors, especially when coupled with the fact that much of our product prices are determined on a daily basis, can, and at times do, lead to wide fluctuations in the prices we receive.

Based on our 2004 production, a $.10 per Mcf change in what we receive for our natural gas production would result in a corresponding $211,800 per month ($2,541,600 annualized) change in our pre-tax operating cash flow. A $1.00 per barrel change in our oil price would have a $81,300 per month ($975,600 annualized) change in our pre-tax operating cash flow. During 2004, substantially all of our natural gas and crude oil volumes were sold at market responsive prices.

In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we sometimes enter into hedging or swap arrangements. Our hedging or swap arrangements apply to only a portion of our

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production and provide only partial price protection against declines in oil and natural gas prices. These hedging or swap arrangements may expose us to risk of financial loss and limit the benefit to us of future increases in prices. A more thorough discussion of our hedging or swap arrangements is contained in the Management’s Discussion and Analysis of Financial Condition and Results of Operation section of this report contained in Item 7.

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. These factors include the availability of funds to carry out their drilling operations. For many of these parties, even if they have the funds available, their decision to spend those funds is often impacted by the then current prices for oil and natural gas. Many of our customers are small to mid-size oil and natural gas companies whose drilling budgets tend to be susceptible to the influences of current price fluctuations. Other factors that affect our ability to work our drilling rigs are: the weather which, under adverse circumstances, can delay or even cause the abandonment of a project by an operator; the competition faced by us in securing the award of a drilling contract in a given area; our experience and recognition in a new market area; and the availability of labor to run our drilling rigs.

Uncertainty of Oil and Natural Gas Reserves.    There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The oil and natural gas reserve data included in this report represents only an estimate of these reserves. Oil and natural gas 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 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:

Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of those oil and natural gas reserves based on risk of recovery, and estimates of the future net cash flows from oil and natural gas reserves prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, oil and natural gas reserve estimates may be subject to periodic downward or upward adjustments. Actual production, revenues and expenditures with respect to our oil 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 and natural gas reserves attributable to our properties. As required by the SEC, the estimated discounted future net cash flows from proved oil and natural gas reserves are determined based on prices and costs as of the date of the estimate. 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:

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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 proved reserves, discounted at 10%. Application of this “ceiling test” generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter 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. We may be required to write down the carrying value of our oil and natural gas properties when oil 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.

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 contract drilling operations, our ongoing exploration and development programs and our expanding natural gas purchasing, gathering and processing operations. Historically, we have funded our working capital needs through a combination of internally generated cash flow, equity financing and borrowings under our bank credit agreement. We currently have, and will continue to have, a certain amount of indebtedness. At December 31, 2004, our outstanding long-term debt was $95.5 million.

Our level of debt, the cash flow needed to satisfy our debt and the covenants contained in our bank credit agreement could:

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 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, is, to a large extent, a function of the costs associated with the projects we undertake at any given time and the cash flow we receive. Generally, our normal operating costs are those incurred as a result of the drilling of oil and natural gas wells, the acquisition of

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producing properties, the costs associated with the maintenance or expansion of our drilling rig fleet, and the operations of our natural gas purchasing, gathering and processing systems. To some extent, these costs, particularly the first two items, are discretionary and we maintain a degree of control regarding the timing or the need to incur the same. However, in some cases, unforeseen circumstances may arise, such as in the case of an unanticipated opportunity to acquire a large producing property package or the need to replace a costly rig component due to an unexpected loss, which could force us to incur increased 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.

Executive Officers.    The table below and accompanying text sets forth certain information concerning each of our executive officers as of March 1, 2005.

Mr. Nikkel joined Unit as its President, Chief Operating Officer and a director in 1983. He was elected its Chief Executive Officer in July, 2001 and Chairman of the Board in August, 2003. He currently holds the position of Chairman of the Board and Chief Executive Officer. From 1976 until January, 1982 when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and director of Cotton Petroleum Corporation, serving as the President of Cotton from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last serving as Division Geologist for Amoco’s Denver Division. Mr. Nikkel presently serves as President and a director of Nike Exploration Company. From August 16, 2000 until August 23, 2002 Mr. Nikkel, in connection with Unit’s investment in the company, also served as a director of Shenandoah Resources Ltd., a Canadian company. Shenandoah Resources Ltd. filed for creditors’ protection under The Companies’ Creditor Arrangement Act in April 2002 with the Court of Queen’s Bench of Alberta, Judicial District of Calgary. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University.

Mr. Pinkston joined Unit in December, 1981. He had served as Corporate Budget Director and Assistant Controller prior to being appointed Controller in February, 1985. In December, 1986 he was elected Treasurer of the company and was elected to the position of Vice President and Chief Financial Officer in May, 1989. In August, 2003, he was elected to the position of President of the company. He was elected a director of the company by the Board in January, 2004. In February, 2004, in addition to his position as President, he was elected to the office of Chief Operating Officer. Mr. Pinkston holds the offices of President and Chief Operating

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Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma and is a Certified Public Accountant.

Mr. Schell joined Unit in January 1987, as its Secretary and General Counsel. In December 2002, he was elected to the additional position as Senior Vice President. From 1979 until joining Unit, Mr. Schell was Counsel, Vice President and a member of the Board of Directors of C&S Exploration, Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa Law School. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel Association and the American Society of Corporate Secretaries.

Mr. Merrill joined Unit in August 2003 and served as its Vice President of Finance until February 2004 when he was elected to the position of Chief Financial Officer and Treasurer. From May 1999 through August 2003, Mr. Merrill served as Senior Vice President, Finance with TV Guide Networks, Inc. From July 1996 through May 1999 he was a Senior Manager with Deloitte & Touche LLP. From July 1994 through July 1996 he was Director of Financial Reporting and Special Projects for MAPCO, Inc. He began his career as an auditor with Deloitte, Haskins & Sells in 1983. Mr. Merrill received a Bachelor of Business Administration Degree in Accounting from the University of Oklahoma and is a Certified Public Accountant.

We are a party to various legal proceedings arising in the ordinary course of our business, none of which, in our opinion, will result in judgments which would have a material adverse effect on our financial position, operating results or cash flows.

No matters were submitted to our security holders during the fourth quarter of 2004.

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PART II

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:

On March 1, 2005 there were 1,606 record holders of our common stock.

We have never paid cash dividends on our common stock and currently intend to continue our policy of retaining earnings from our operations. Our credit agreement prohibits us from declaring and paying dividends (other than stock dividends) in any fiscal year in an amount greater than 25% of our preceding year’s consolidated net income.

See Item 7. Management’s Discussion of Financial Condition and Results of Operation for a review of 2004, 2003 and 2002 activity.

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FINANCIAL CONDITION AND LIQUIDITY

Summary.    Our financial condition and liquidity depends on the cash flow from our three principal business segments (and our subsidiaries that carry out those operations) and borrowings under our bank credit agreement. Our cash flow is influenced mainly by:

At December 31, 2004, we had cash totaling $665,000 and we had borrowed $95.5 million of the $150.0 million we had elected to have available under our credit agreement.

Our three principal business segments are:

The following is a summary of certain financial information as of December 31, 2004 and for the years ended December 31, 2004 and December 31, 2003:

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The following table summarizes certain operating information for the years ended December 31, 2004 and 2003: