Management's Discussion and Analysis (MD&A) provides an understanding of operating results and financial condition by focusing on changes in key measures from year to year. MD&A is organized in the following sections:

• Financial Condition
• Results of Operations
• New Accounting Pronouncements

MD&A should be read in conjunction with the Consolidated Condensed Financial Statements and related notes included in this report as well as the information contained in our Annual Report on Form 10-K.

Unless otherwise indicated or required by the content, as used in this report, the terms company, Unit, us, our, we and its refer to Unit Corporation and, as appropriate, and/or one or more of its subsidiaries.

FINANCIAL CONDITION

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 facility.

Our cash flow is influenced mainly by:

• the prices we receive for our natural gas production and, to a lesser extent, the prices we receive for our oil production;
• the quantity of natural gas and oil we produce;
• the demand for and the dayrates we receive for our drilling rigs; and
• the margins we obtain from our natural gas gathering and processing contracts.

Our three principal business segments are:

• contract drilling carried out by our subsidiaries Unit Drilling Company and it subsidiaries Unit Texas Drilling, L.L.C. and Leonard Hudson Drilling Company;
• oil and natural gas exploration, carried out by our subsidiary Unit Petroleum Company; and its subsidiaries; and
• mid stream operations (consisting of natural gas buying, selling, gathering, processing and treating) carried outby our subsidiary Superior Pipeline Company, L.L.C.

The following is a summary of certain financial information as of June 30, 2007 and 2006 and for the six months ended June 30, 2007 and 2006:

                                  June 30,          June 30,      Percent
                                    2007              2006        Change
                                 (In thousands except percent amounts)

Working Capital              $        87,311    $      75,659          15 %
Long-Term Debt               $       209,800    $     129,700          62 %
Shareholders' Equity         $     1,293,040    $     992,101          30 %
Ratio of Long-Term Debt to                14 %             12 %        17 %
Total Capitalization
Net Income                   $       130,048    $     149,730         (13 )%
Net Cash From Operating      $       219,352    $     223,485          (2 )%
Activities
Net Cash Used in Investing   $      (258,753 )  $    (210,407 )        23 %
Activities
Net Cash From (Used in)
Financing Activities         $        39,390    $     (13,224 )       398 %

The following table summarizes certain operating information for the six months ended June 30, 2007 and 2006:

                                  June 30,    June 30,      Percent
                                    2007        2006        Change
Oil Production (MBbls)                  789         685          15 %
Natural Gas Production (MMcf)        21,301      21,150           1 %
Average Oil Price Received        $   50.66   $   55.88          (9 )%
Average Oil Price Received        $   50.66   $   55.88          (9 )%
Excluding Hedges
Average Natural Gas Price         $    6.58   $    6.41           3 %
Received
Average Natural Gas Price         $    6.57   $    6.41           2 %
Received Excluding Hedges
Average Number of Our Drilling
Rigs in Use During
the Period                             97.4       109.5         (11 )%
Total Number of Drilling Rigs
Available at the End
of the Period                           128         115          11 %
Average Dayrate                   $  19,062   $  17,870           7 %
Gas Gathered-MMBtu/day              222,164     229,448          (3 )%
Gas Processed-MMBtu/day              42,984      30,835          39 %
Gas Liquids Sold-Gallons/day        104,946      50,749         107 %
Number of Active Natural Gas             37          37         --- %
Gathering Systems
Number of Active Processing               7           6          17 %
Systems

At June 30, 2007, we had unrestricted cash totaling $0.6 million and we had borrowed $209.8 million of the $275.0 million we have elected to have available under our Credit Facility.

Our Bank Credit Facility. On May 24, 2007, we entered into a First Amended and Restated Senior Credit Agreement (Credit Facility) which amended and restated the credit facility entered into between us and our lenders on January 30, 2004. The Credit Facility is a revolving credit facility maturing on May 24, 2012 and has a maximum credit amount of $400.0 million. Borrowings under the Credit Facility are limited to a commitment amount elected by us. On May 24, 2007, we elected to have an initial aggregate commitment amount of $275.0 million. We are charged a commitment fee of 0.25 to 0.375 of 1% on the amount available but not borrowed with the rate varying based on the amount borrowed as a percentage of our total borrowing base amount. We incurred origination, agency and syndication fees of $737,500 at the inception of the Credit Facility. These fees are being amortized over the life of the agreement. The average interest rate for the first six months of 2007 was 6.5%. At June 30, 2007 and July 31, 2007, our borrowings were $209.8 million and $197.8 million, respectively.

The borrowing base under the Credit Facility is subject to re-determination on April 1 and October 1 of each year. The current borrowing base as determined by the lenders is $425.0 million. Each re-determination is based primarily on a percentage of the discounted future value of our oil and natural gas reserves, as determined by the lenders, and to a lesser extent, the loan value the lenders reasonably attribute to Superior Pipeline Company's cash flow as defined in the Credit Facility. The Credit Facility allows for one requested special re-determination of

the borrowing base by either the banks or us between each scheduled re-determination date and additional redeterminations may be requested by us following the consummation of any acquisition as defined in the Credit Facility. The lender's aggregate commitment is limited to the lesser of the amount of the borrowing base or $400 million.

At our election, any part of the outstanding debt may be fixed at a London Interbank Offered Rate (LIBOR) Rate for a 30, 60, 90 or 180 day term. During any LIBOR Rate funding period the outstanding principal balance of the note to which such LIBOR Rate option applies may be repaid on three days prior notice to the administrative agent and subject to the payment of any applicable funding indemnification amounts. Interest on the LIBOR Rate is computed at the LIBOR Base Rate applicable for the interest period plus 1.00% to 1.75% depending on the level of debt as a percentage of the borrowing base and payable at the end of each term or every 90 days whichever is less. Borrowings not under the LIBOR Rate bear interest at the BOKF National Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty. At June 30, 2007, all of the $209.8 million we had borrowed was subject to the LIBOR rate.

The Credit Facility includes prohibitions against:

. the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year,

. the incurrence of additional debt with certain limited exceptions, and

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

The Credit Facility also requires that we have at the end of each quarter:

. consolidated net worth of at least $900 million,

. a current ratio (as defined in the Credit Facility) of not less than 1 to 1, and

. a leverage ratio of long-term debt to consolidated EBITDA (as defined in the Credit Facility) for the most recently ended rolling four fiscal quarters of no greater than 3.50 to 1.0.

On June 30, 2007, we were in compliance with the Credit Facility's covenants.

In February 2005, we entered into an interest rate swap to help manage our exposure to possible future interest rate increases. The contract swaps $50.0 million of variable rate debt to fixed and covers the period from March 1, 2005 through January 30, 2008. The fixed rate is 3.99%. The swap is a cash flow hedge. As a result of this interest rate swap, our interest expense was decreased by $0.3 million in the first six months of 2007. The fair value of the swap was recognized on the June 30, 2007 balance sheet as current and non-current derivative assets totaling $0.4 million and a gain of $0.3 million, net of tax, in accumulated other comprehensive income.

Contractual Commitments. At June 30, 2007 we had the following contractual obligations:

                                                    Payments Due by Period
                                                  Less
         Contractual                             Than 1      2-3         4-5       After 5
         Obligations                  Total       Year      Years       Years       Years
                                                        (In thousands)
Bank Debt (1)                       $ 270,328   $ 12,376   $ 24,684   $ 233,268   $     ---
Retirement Agreements (2)               1,059        726        333         ---         ---
Operating Leases (3)                    4,232      1,479      2,386         367         ---
Drill Pipe, Drilling Rigs and
Equipment Purchases (4)                19,071     19,071        ---         ---         ---
Total Contractual
Obligations                         $ 294,690   $ 33,652   $ 27,403   $ 233,635   $     ---

(1) See the previous discussion in Management Discussion and Analysis regarding our bank credit facility. This obligation is presented in accordance with the terms of the credit facility and includes interest calculated at the June 30, 2007 interest rate of 6.48% including the effect of the interest rate swap related to $50.0 million of the outstanding debt.

(2) In the second quarter of 2001, we recorded $1.3 million in additional employee benefit expense for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, will be paid in monthly payments of $25,000 starting in July 2003 and continuing through June 2009. In the first quarter of 2004, we acquired a liability for the present value of a separation agreement between PetroCorp Incorporated and one of its previous officers. The liability associated with this agreement will be paid in quarterly payments of $12,500 through December 31, 2007. In the first quarter of 2005, we recorded $0.7 million in additional employee benefit expense for the present value of a separation agreement made in connection with the retirement of John Nikkel from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, will be paid in monthly payments of $31,250 starting in November 2006 and continuing through October 2008. These liabilities as presented above are undiscounted.

(3) We lease office space in Tulsa and Woodward, Oklahoma; Houston and Midland, Texas; and Denver, Colorado under the terms of operating leases expiring through January 31, 2012. Additionally, we have several equipment leases and lease space on short-term commitments to stack excess drilling rig equipment and production inventory.

(4) Due to the potential for limited availability of new drill pipe within the industry, we have committed to purchase approximately $16.6 million of drill pipe and drill collars. We have also committed to purchase $3.1 million of drilling rig components with 20% or $0.6 million paid through June 30, 2007.

At June 30, 2007, we also had the following commitments and contingencies that could create, increase or accelerate our liabilities:

                                                     Amount of Commitment Expiration
                                                               Per Period
                                   Total
                                   Amount
                                 Committed      Less
        Other                        Or        Than 1        2-3         4-5       After 5
     Commitments                  Accrued       Year        Years       Years       Years
                                                             (In thousands)
Deferred Compensation
Agreement (1)                    $    2,829     Unknown     Unknown     Unknown     Unknown
Separation Benefit
Agreement (2)                    $    3,999     Unknown     Unknown     Unknown     Unknown
Plugging Liability (3)           $   34,419   $   1,629   $   1,558   $   3,188   $  28,044
Gas Balancing
Liability (4)                    $    1,080     Unknown     Unknown     Unknown     Unknown
Repurchase
Obligations (5)                     Unknown     Unknown     Unknown     Unknown     Unknown
Workers' Compensation
Liability (6)                    $   22,503   $   8,106   $   4,067   $   1,469   $   8,861

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

(2) Effective January 1, 1997, we adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with the company up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against us in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of the company with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered in this plan. On May 5, 2004 we also adopted the Special Separation Benefit Plan ("Special Plan"). This plan is identical to the Separation Benefit Plan with the exception that the benefits under the plan vest on the earliest of a participant's reaching the age of 65 or serving 20 years with the company. At June 30, 2007, there were 33 eligible employees to participate in the plan.

(3) When a well is drilled or acquired, under Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143), we have recorded the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells).

(4) We have recorded a liability for certain properties where we believe there are insufficient oil and natural gas reserves available to allow the under-produced owners to recover their under-production from future production volumes.

(5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2007, with a subsidiary of ours serving as general partner. The Partnerships were formed for the purpose of conducting oil and natural gas

acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of that year. These partnership agreements require, on the election of a limited partner, that we repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20% of the units outstanding. We made repurchases of $7,000, $4,000 and $14,000 in 2006, 2005 and 2004, respectively and have not had any repurchases in 2007.

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

Hedging. Periodically we hedge the prices we will receive for a portion of our future natural gas and oil production and mid-stream activities. We do so in an attempt to reduce the impact and uncertainty that price variations have on our cash flow.

In June 2007, we entered into the following natural gas liquids sales swaps and natural gas purchase swaps to lock in a percentage of our Mid-Stream segment's frac spread for natural gas processed. The frac spread is the difference in the value received for liquids recovered from natural gas in comparison to the amount received for the equivalent MMBtu's of natural gas if unprocessed. These swaps pertain to approximately 65% of our Mid-Stream segments total liquid sales. The following table provides additional information pertaining to the swap contracts for the time periods covering July through November of 2007:

    Commodity        Quantity            Price    Underlying Commodity Price
    Ethane           623,868 gal./month  $ 0.6225 OPIS Ethane Conway
    Propane          396,690 gal./month  $ 1.1475 OPIS Propane Conway
    Propane          396,690 gal./month  $ 1.15   OPIS Propane Conway
    Iso Butane       61,782 gal./month   $ 1.2625 OPIS Iso Butane Conway
    Iso Butane       61,782 gal./month   $ 1.2975 OPIS Iso Butane Conway
    Normal Butane    163,632 gal./month  $ 1.2975 OPIS Normal Butane Conway

All of these swaps are cash flow hedges and there is no material amount of ineffectiveness. The fair value of the swap contracts was recognized on the June 30, 2007 balance sheet as a derivative liability of $1.7 million and a loss of $1.0 million, net of tax, in accumulated other comprehensive income.

In January and February 2007, we entered into the following two natural gas collar contracts:

   First Contract:
            Production volume covered   10,000 MMBtu/day
            Period covered              May through December of 2007
            Prices                      Floor of $6.00 and a ceiling of $10.00
            Underlying commodity price  Centerpoint Energy Gas Transmission Co.,
                                          East - Inside FERC

   Second Contract:
            Production volume covered   10,000 MMBtu/day
            Period covered              March through December of 2007
            Prices                      Floor of $6.25 and a ceiling of $9.25
            Underlying commodity price  Centerpoint Energy Gas Transmission Co.,
                                          East - Inside FERC

In December 2006, we entered into the following natural gas collar contract:

  Contract:
            Production volume covered   10,000 MMBtu/day
            Period covered              January through December of 2007
            Prices                      Floor of $6.00 and a ceiling of $9.60
            Underlying commodity price  Centerpoint Energy Gas Transmission Co.,
                                          East - Inside FERC

All of these hedges are cash flow hedges and there is no material amount of ineffectiveness. The fair value of the collar contracts was recognized on the June 30, 2007 balance sheet as a derivative asset of $1.4 million and at a gain of $0.9 million, net of tax, in accumulated other comprehensive income.

We did not have any oil, natural gas or natural gas liquids hedges outstanding at June 30, 2006.

In February 2005, we entered into an interest rate swap to help manage our exposure to possible future interest rate increases. The contract swaps $50.0 million of variable rate debt to fixed and covers the period from March 1, 2005 through January 30, 2008. The fixed rate is based on three-month LIBOR and is at 3.99%. The swap is a cash flow hedge. As a result of this interest rate swap, our interest expense was decreased by $0.2 million in the second quarter of 2007 and $0.3 million for the six months ended June 30, 2007. In the second quarter and first six months of 2006, our interest expense was decreased by $0.1 million and $0.2 million, respectively, as a result of the interest rate swap. The fair value of the swap was recognized on the June 30, 2007 balance sheet as current and non-current derivative assets totaling $0.4 million and a gain of $0.3 million, net of tax, in accumulated other comprehensive income.

Self-Insurance or Retentions. We are self-insured for certain losses relating to workers' compensation, general liability, property damage, control of well and employee medical benefits. In addition, our insurance policies contain deductibles or retentions per occurrence that range from $0.5 million for Oklahoma workers' compensation to $1.0 million for general liability and drilling rig physical damage. We have purchased stop-loss coverage in order to limit, to the extent feasible, our per occurrence and aggregate exposure to certain types of claims. However, there is no assurance that the insurance coverage we have will adequately protect us against liability from all potential consequences. If our insurance coverage becomes more expensive, we may choose to decrease our limits and increase our deductibles rather than pay higher premiums. With respect to our drilling operations conducted by Unit Texas Drilling LLC in Texas, we have elected to use an ERISA governed occupational injury benefit plan to cover that company's field and support staff in lieu of covering them under an insured Texas workers' compensation plan.

Impact of Prices for Our Oil and Natural Gas. Natural gas comprises 85% of our total oil and natural gas reserves. Any significant change in natural gas prices has a material effect on our revenues, cash flow and the value of our oil and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances and by world wide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we can not predict nor measure their future influence on the prices we will receive.

Based on our first six months 2007 production, a $0.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $334,000 per month ($4.0 million annualized) change in our pre-tax operating cash flow. Our first six month 2007 average natural gas price was $6.57 compared to an average natural gas price of $6.41 for the first six months of 2006. A $1.00 per barrel change in our oil price would have a $124,000 per month ($1.5 million annualized) change in our pre-tax operating cash flow based on our production in the first six months of 2007. Our first six month 2007 average oil price was $50.66 compared with an average oil price of $55.88 received in the first six months of 2006.

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

Most of our natural gas production is sold to third parties under month-to-month contracts.

Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures are discretionary and directed toward future growth. Our decision to increase our oil and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We drilled 121 wells (42.31 net wells) in the first six months of 2007 compared to 103 wells (38.65 net wells) in the first six months of 2006. Our total capital expenditures for oil and natural gas exploration in the first six months of 2007 totaled $135.1 million. We currently anticipate we will drill approximately 270 gross wells in 2007. We have estimated our total 2007 capital expenditures for oil and natural gas exploration to be approximately $326.0 million Whether we are able to drill the number of wells we anticipate drilling in 2007 is dependent on a number of factors, many of which are beyond our control and include the availability of drilling rigs, the weather and the efforts of our outside industry partners.

On May 16, 2006, we closed the acquisition of certain oil and natural gas properties from a group of private entities for approximately $32.4 million in cash. Proved oil and natural gas reserves involved in this acquisition consisted of approximately 14.2 Bcfe. The effective date of this acquisition was April 1, 2006 and results from this acquisition were included in the statement of income beginning May 1, 2006.

On October 13, 2006, we completed the acquisition of Brighton Energy, L.L.C., a privately owned oil and natural gas company for approximately $67.0 million in cash. Included in this acquisition were all of Brighton's oil and natural gas assets (excluding Atoka and Coal counties in Oklahoma) and included approximately 23.1 Bcfe of proved reserves. The majority of the acquired reserves are located in the Anadarko Basin of Oklahoma and the onshore Gulf Coast basins of Texas and Louisiana, with additional reserves in Arkansas, Kansas, Montana, North Dakota and Wyoming. This acquisition had an effective date of August 1, 2006 and results of operations from this acquisition are included in the statement of income beginning October 1, 2006 with the results for the period from August 1, 2006 through September 30, 2006 included as an adjustment to the purchase price.

Contract Drilling. Our drilling work is subject to many factors that influence the number of drilling rigs we have working as well as the costs and revenues associated with that work. These factors include the demand for drilling rigs, competition from other drilling contractors, the prevailing prices for natural gas and oil, availability and cost of labor to run our rigs and our ability to supply the equipment needed.

Although rig utilization declined in the fourth quarter of 2006 and continued to slowly decline in the first six months of 2007, we do not anticipate declines in labor cost per hour due to the competition within the industry to keep qualified employees and attract individuals with the skills required to meet the future technological requirements of the drilling industry. To help keep qualified labor, we previously implemented longevity pay incentives and as recently as the . . .