**SECURITIES
      AND EXCHANGE COMMISSION**
 **Washington,
      D.C. 20549**
  **Form
      10-Q**
  **[x]
                QUARTERLY REPORT PURSUANT TO SECTION 13 OR
                15(d)**
 **OF
                THE SECURITIES EXCHANGE ACT OF
                1934**
  **For
      the quarterly period ended June 30, 2007**
  **OR**
  **[  ]
                TRANSITION REPORT PURSUANT TO SECTION 13 OR
                15(d)**
 **OF
                THE SECURITIES EXCHANGE ACT OF
                1934**
 
 For
      the
      transition period from _________ to _________
  [Commission
      File Number 1-9260]
  **UNIT
      CORPORATION**
 (Exact
      name of registrant as specified in its charter)
 
 **Delaware**
            **73-1283193**(State
                or other jurisdiction of incorporation)
            (I.R.S.
                Employer Identification No.)
  **7130
                South Lewis, Suite 1000, Tulsa, Oklahoma**
            **74136**(Address
                of principal executive offices)
            (Zip
                Code)
  
 **(918)
                493-7700**(Registrant’s
                telephone number, including area
                code)
 
 **None**(Former
                name, former address and former fiscal year,if
                changed since last report)
  
  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 is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer.
 
 Large
                accelerated filer [x]
            Accelerated
                filer [  ]
            Non-accelerated
                filer [  ]
 
 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
      July 31, 2007, 46,430,960 shares of the issuer's common stock were
      outstanding.
  
 
 **FORM
      10-Q**
 **UNIT
      CORPORATION**
 
 **TABLE
      OF CONTENTS**
 PageNumberPART
                I. Financial Informat**ion**Item
                1.
            Financial
                Statements (Unaudited)Consolidated
                Condensed Balance SheetsJune
                30, 2007 and December 31, 2006
            2Consolidated
                Condensed Statements of IncomeThree
                and Six Months Ended June 30, 2007 and 2006
            4Consolidated
                Condensed Statements of Cash FlowsSix
                Months Ended June 30, 2007 and 2006
            5Consolidated
                Condensed Statements of Comprehensive IncomeThree
                and Six Months Ended June 30, 2007 and 2006
            6Notes
                to Consolidated Condensed Financial Statements
            7Report
                of Independent Registered Public Accounting Firm
            18Item
                2.
            Management’s
                Discussion and Analysis of FinancialCondition
                and Results of Operations
            19Item
                3.
            Quantitative
                and Qualitative Disclosure about Market Risk
            37Item
                4.
            Controls
                and Procedures
            37PART
                II. Other InformationItem
                1.
            Legal
                Proceedings
            38Item
                1A.
            Risk
                Factors
            38Item
                2.
            Unregistered
                Sales of Equity Securities and Use of Proceeds
            38Item
                3.
            Defaults
                Upon Senior Securities
            38Item
                4.
            Submission
                of Matters to a Vote of Security Holders
            38Item
                5.
            Other
                Information
            39Item
                6.
            Exhibits
            39Signatures
            
            40
  1
  **PART
      I. FINANCIAL INFORMATION**
 
 **Item
      1.    Financial Statements**
 
 **UNIT
      CORPORATION AND SUBSIDIARIES**
 **CONSOLIDATED
      CONDENSED BALANCE SHEETS (UNAUDITED)**
 
 **June
                30,**
            
            
            
            **December
                31,****2007**
            
            
            
            **2006****(In
                thousands)****ASSETS**Current
                Assets:Cash
                and cash equivalents
            
            $
            578
            
            
            
            $
            589Restricted
                cash
            
            
            19
            
            
            
            
            18Accounts
                receivable
            
            
            205,578
            
            
            
            
            200,415Materials
                and supplies
            
            
            18,997
            
            
            
            
            18,901Other
            
            
            12,209
            
            
            
            
            13,017Total
                current assets
            
            
            237,381
            
            
            
            
            232,940Property
                and Equipment:Drilling
                equipment
            
            
            914,646
            
            
            
            
            781,190Oil
                and natural gas properties, on the full costmethod:Proved
                properties
            
            
            1,455,960
            
            
            
            
            1,330,010Undeveloped
                leasehold not being amortized
            
            
            61,039
            
            
            
            
            53,687Gas
                gathering and processing equipment
            
            
            103,351
            
            
            
            
            85,339Transportation
                equipment
            
            
            22,808
            
            
            
            
            20,749Other
            
            
            19,270
            
            
            
            
            17,0822,577,074
            
            
            
            
            2,288,057Less
                accumulated depreciation, depletion, amortizationand
                impairment
            
            
            825,820
            
            
            
            
            735,394Net
                property and equipment
            
            
            1,751,254
            
            
            
            
            1,552,663Goodwill
            
            
            63,071
            
            
            
            
            57,524Other
                Intangible Assets, Net
            
            
            15,782
            
            
            
            
            17,087Other
                Assets
            
            
            14,108
            
            
            
            
            13,882Total
                Assets
            
            $
            2,081,596
            
            
            
            $
            1,874,096
 
 
 
 
 
 
 
 
 
 
 
 The
      accompanying notes are an integral part of the
 consolidated
      condensed financial statements.
  2
  **UNIT
      CORPORATION AND SUBSIDIARIES**
 **CONSOLIDATED
      CONDENSED BALANCE SHEETS (UNAUDITED) - CONTINUED**
 
 **June
                30,**
            
            
            
            **December
                31,****2007**
            
            
            
            **2006****(In
                thousands)****LIABILITIES
                AND SHAREHOLDERS’ EQUITY**Current
                Liabilities:Accounts
                payable
            
            $
            90,705
            
            
            
            $
            92,125Accrued
                liabilities
            
            
            39,151
            
            
            
            
            52,166Income
                taxes payable
            
            
            3,220
            
            
            
            
            2,956Contract
                advances
            
            
            6,533
            
            
            
            
            5,061Current
                portion of other liabilities
            
            
            10,461
            
            
            
            
            8,634Total
                current liabilities
            
            
            150,070
            
            
            
            
            160,942Long-Term
                Debt
            
            
            209,800
            
            
            
            
            174,300Other
                Long-Term Liabilities
            
            
            55,428
            
            
            
            
            55,741Deferred
                Income Taxes
            
            
            373,258
            
            
            
            
            325,077Shareholders’
                Equity:Preferred
                stock, $1.00 par value, 5,000,000 sharesauthorized,
                none issued
            
            
            ---
            
            
            
            
            ---Common
                stock, $.20 par value, 175,000,000 sharesauthorized,
                46,424,360 and 46,283,990 sharesissued,
                respectively
            
            
            9,279
            
            
            
            
            9,257Capital
                in excess of par value
            
            
            339,992
            
            
            
            
            333,833Accumulated
                other comprehensive income
            
            
            114
            
            
            
            
            1,339Retained
                earnings
            
            
            943,655
            
            
            
            
            813,607Total
                shareholders’ equity
            
            
            1,293,040
            
            
            
            
            1,158,036Total
                Liabilities and Shareholders’ Equity
            
            $
            2,081,596
            
            
            
            $
            1,874,096
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 The
      accompanying notes are an integral part of the
 consolidated
      condensed financial statements.
  3
  **UNIT
      CORPORATION AND SUBSIDIARIES**
 **CONSOLIDATED
      CONDENSED STATEMENTS OF INCOME (UNAUDITED)**
 
 **Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006****(In
                thousands except per share amounts)**Revenues:Contract
                drilling
            $
            154,349
            
            $
            175,908
            
            $
            314,634
            
            $
            337,338Oil
                and natural gas
            
            96,343
            
            
            81,954
            
            
            182,449
            
            
            176,280Gas
                gathering and processing
            
            35,769
            
            
            21,720
            
            
            66,537
            
            
            47,202Other
            
            179
            
            
            767
            
            
            291
            
            
            2,337Total
                revenues
            
            286,640
            
            
            280,349
            
            
            563,911
            
            
            563,157Expenses:Contract
                drilling:Operating
                costs
            
            74,729
            
            
            79,117
            
            
            151,016
            
            
            159,426Depreciation
            
            13,682
            
            
            12,845
            
            
            26,399
            
            
            24,686Oil
                and natural gas:Operating
                costs
            
            24,461
            
            
            18,988
            
            
            46,600
            
            
            37,294Depreciation,
                depletion andamortization
            
            30,723
            
            
            25,041
            
            
            60,070
            
            
            49,223Gas
                gathering and processing:Operating
                costs
            
            31,395
            
            
            18,717
            
            
            58,896
            
            
            41,518Depreciation
                and amortization
            
            2,555
            
            
            1,232
            
            
            4,894
            
            
            2,382General
                and administrative
            
            5,247
            
            
            4,402
            
            
            10,429
            
            
            8,368Interest
            
            1,729
            
            
            1,017
            
            
            3,370
            
            
            2,007Total
                expenses
            
            184,521
            
            
            161,359
            
            
            361,674
            
            
            324,904Income
                Before Income Taxes
            
            102,119
            
            
            118,990
            
            
            202,237
            
            
            238,253Income
                Tax Expense:Current
            
            19,649
            
            
            33,141
            
            
            42,346
            
            
            63,299Deferred
            
            16,904
            
            
            11,032
            
            
            29,843
            
            
            25,224Total
                income taxes
            
            36,553
            
            
            44,173
            
            
            72,189
            
            
            88,523Net
                Income
            $
            65,566
            
            $
            74,817
            
            $
            130,048
            
            $
            149,730Net
                Income per Common Share:Basic
            $
            1.41
            
            $
            1.62
            
            $
            2.81
            
            $
            3.24Diluted
            $
            1.41
            
            $
            1.61
            
            $
            2.79
            
            $
            3.23
 
 
 
 The
      accompanying notes are an integral part of the
 consolidated
      condensed financial statements.
  4
  **UNIT
      CORPORATION AND SUBSIDIARIES**
 **CONSOLIDATED
      CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)**
 
 **Six
                Months Ended****June
                30,****2007**
            
            
            
            **2006****(In
                thousands)**Cash
                Flows From Operating Activities:Net
                income
            
            $
            130,048
            
            
            
            $
            149,730Adjustments
                to reconcile net income to net cashprovided
                (used) by operating activities:Depreciation,
                depletion and amortization
            
            
            91,807
            
            
            
            
            76,640Deferred
                tax expense
            
            
            29,843
            
            
            
            
            25,224Other
            
            
            5,080
            
            
            
            
            3,566Changes
                in operating assets and liabilitiesincreasing
                (decreasing) cash:Accounts
                receivable
            
            
            (5,163
            )
            
            
            
            7,650Accounts
                payable
            
            
            (22,029
            )
            
            
            
            (30,993
            )Material
                and supplies inventory
            
            
            (96
            )
            
            
            
            (669
            )Accrued
                liabilities
            
            
            (12,510
            )
            
            
            
            (14,114
            )Contract
                advances
            
            
            1,472
            
            
            
            
            5,304Other
                – net
            
            
            900
            
            
            
            
            1,147Net
                cash from operating activities
            
            
            219,352
            
            
            
            
            223,485Cash
                Flows From (Used In) Investing Activities:Capital
                expenditures (including producing property,drilling
                rig and other acquisitions)
            
            
            (262,031
            )
            
            
            
            (214,452
            )Proceeds
                from disposition of assets
            
            
            3,279
            
            
            
            
            3,795Other-net
            
            
            (1
            )
            
            
            
            250Net
                cash used in investing activities
            
            
            (258,753
            )
            
            
            
            (210,407
            )Cash
                Flows From (Used In) Financing Activities:Borrowings
                under line of credit
            
            
            124,900
            
            
            
            
            115,600Payments
                under line of credit
            
            
            (89,400
            )
            
            
            
            (130,900
            )Proceeds
                from exercise of stock options
            
            
            605
            
            
            
            
            654Book
                overdrafts
            
            
            3,285
            
            
            
            
            1,422Net
                cash from (used in) financing activities
            
            
            39,390
            
            
            
            
            (13,224
            )Net
                Decrease in Cash and Cash Equivalents
            
            
            (11
            )
            
            
            
            (146
            )Cash
                and Cash Equivalents, Beginning of Period
            
            
            589
            
            
            
            
            947Cash
                and Cash Equivalents, End of Period
            
            $
            578
            
            
            
            $
            801
 
 The
      accompanying notes are an integral part of the
 consolidated
      condensed financial statements.
  5
  **UNIT
      CORPORATION AND SUBSIDIARIES**
 **CONSOLIDATED
      CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)**
 
 **Three
                Months Ended**
            
            
            
            **Six
                Months Ended****June
                30,**
            
            
            
            **June
                30,****2007**
            
            **2006**
            
            
            
            **2007**
            
            **2006****(In
                thousands)**Net
                Income
            
            $
            65,566
            
            $
            74,817
            
            
            
            $
            130,048
            
            $
            149,730Other
                Comprehensive Income,Net
                of Taxes:Change
                in value ofderivative
                instrumentsused
                as cash flowhedges
                (net of taxof
                $363, $91, $(514)and
                $225)
            
            
            630
            
            
            155
            
            
            
            
            (904
            )
            
            379Reclassification
                -Derivative
                settlements (netof
                tax of $(62), $(41),$(176)
                and $(70))
            
            
            (112
            )
            
            (69
            )
            
            
            
            (321
            )
            
            (119
            )Comprehensive
                Income
            
            $
            66,084
            
            $
            74,903
            
            
            
            $
            128,823
            
            $
            149,990
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 The
      accompanying notes are an integral part of the
 consolidated
      condensed financial statements.
  6
  **UNIT
      CORPORATION AND SUBSIDIARIES**
 **NOTES
      TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS**
 
 **NOTE
      1 - BASIS OF PREPARATION AND PRESENTATION**
 
 The
      accompanying unaudited consolidated condensed financial statements include
      the
      accounts of Unit Corporation and its directly or indirectly wholly owned
      subsidiaries (company) and have been prepared under the rules and regulations
      of
      the Securities and Exchange Commission (SEC). As applicable under these
      regulations, certain information and footnote disclosures have been condensed
      or
      omitted and the consolidated condensed financial statements do not include
      all
      disclosures required by accounting principles generally accepted in the United
      States of America. In the opinion of the company, the unaudited consolidated
      condensed financial statements contain all adjustments necessary (all
      adjustments are of a normal recurring nature) to state fairly the interim
      financial information.
 
 Results
      for the three months and six months ended June 30, 2007 are not necessarily
      indicative of the results to be realized during the full year. The consolidated
      condensed financial statements should be read with the company’s Annual Report
      on Form 10-K for the year ended December 31, 2006.  With respect to
      the unaudited financial information for the three and six month periods ended
      June 30, 2007 and 2006 included in this Form 10-Q, PricewaterhouseCoopers LLP
      reported that they have applied limited procedures in accordance with
      professional standards for a review of that information.  However, their
      Report dated August 2, 2007 which is included in this quarterly report, states
      that they did not audit and they do not express an opinion on that unaudited
      financial information.  Accordingly, the reliance placed on their report
      should be restricted in light of the limited review procedures applied. 
PricewaterhouseCoopers LLP is not subject to the liability provisions of Section
      11 of the Securities Act of 1933 for their report on the unaudited financial
      information because that report is not a "report" or a "part" of a registration
      statement prepared or certified by PricewaterhouseCoopers LLP within the meaning
      of Sections 7 and 11 of the Act.
 
 Before
      January 1, 2006, the company accounted for its stock-based compensation plans
      under the recognition and measurement principles of APB 25, “Accounting for
      Stock Issued to Employees,” and related Interpretations. Under APB 25, no
      stock-based employee compensation costs relating to stock options was not
      reflected in net income since all options granted under the company’s plans had
      an exercise price equal to the market value of the underlying common stock
      on
      the date of grant.
  On
      January 1, 2006, the company adopted Statement of Financial Accounting Standards
      No. 123 (revised 2004), Share-Based Payment, (FAS 123(R)) to account for
      stock-based employee compensation. FAS 123(R) eliminated the use of APB Opinion
      No. 25 and the intrinsic value method of accounting for equity compensation
      and
      requires companies to recognize in their financial statements the cost of
      employee services received in exchange for equity awards based on the grant
      date
      fair value of those awards. The company has elected to use the modified
      prospective method in applying FAS123(R), which requires compensation expense
      to
      be recorded for all unvested stock options and other equity-based compensation
      beginning in the first quarter of adoption. Financial statements for prior
      periods have not been restated.  On adoption of FAS 123(R), the
      company elected to use the "short-cut" method to calculate the historical pool
      of windfall tax benefits in accordance with Financial Accounting Staff Position
      No. FAS 123(R)-3, "Transition Election to Accounting for the Tax Effects of
      Share-Based Payment Awards", issued on November 10, 2005.  For all
      unvested options outstanding as of January 1, 2006, the previously measured
      but
      unrecognized compensation expense, based on the fair value at the original
      grant
      date, is being recognized in the financial statements over the remaining vesting
      period. For equity-based compensation awards granted or modified after December
      31, 2005, compensation expense, based on the fair value on the date of grant
      or
      modification will be recognized in the financial statements over the vesting
      period. To the extent compensation cost relates to employees directly involved
      in oil and natural gas acquisition, exploration and development activities,
      these amounts are capitalized to oil and natural gas properties. Amounts not
      capitalized to oil and natural gas properties are recognized in general and
      administrative expense and operating costs of the company’s business segments.
      The company utilizes the Black-Scholes option pricing model to measure the
      fair
      value of stock options and stock appreciation rights. The value of restricted
      stock grants is based on the closing stock price on the date of the
      grant.
  In
      the
      second quarter and first six months of 2007, the company recognized stock
      compensation expense for restricted stock awards, stock appreciation rights
      and
      stock options of $1.0 million and $1.6 million, respectively and capitalized
      stock compensation cost for oil and natural gas properties of $0.1 million
      and
      $0.2 million,
   7
 
 respectively.
        The tax benefit related to this stock based compensation was $0.2 million
        and
        $0.4 million for the second quarter and first six months of 2007, respectively.
        In the second quarter and first six months of 2006, the company recognized
        stock
        compensation expense for restricted stock awards and stock options of $0.6
        million and $1.3 million, respectively and capitalized stock compensation
        cost
        for oil and natural gas properties of $0.2 million and $0.4 million,
        respectively. The tax benefit related to this stock based compensation was
        $0.2
        million and $0.5 million, respectively for the second quarter and first six
        months of 2006. The remaining unrecognized compensation cost related to unvested
        awards at June 30, 2007 is approximately $3.4 million with $0.6 million of
        this
        amount to be capitalized. The weighted average period of time over which
        this
        cost will be recognized is 0.8 years.
 
 No
      stock
      appreciation rights were granted during the second quarters or first six months
      of 2007 and 2006.
 
 The
      following table estimates the fair value of each option granted during the
      three
      and six month periods ending June 30, 2007 and 2006 using the Black-Scholes
      model applying the estimated values presented in the table:
 
 **Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Options
                Granted
            
            
            28,000
            
            
            33,000
            
            
            28,000
            
            
            33,000Estimated
                Fair Value (In Millions)
            
            $
            0.6
            
            $
            0.8
            
            $
            0.6
            
            $
            0.8Estimate
                of Stock Volatility
            
            
            0.33
            
            
            0.38
            
            
            0.33
            
            
            0.38Estimated
                Dividend Yield
            
            
            ---
            %
            
            ---
            %
            
            ---
            %
            
            ---
            %Risk
                Free Interest Rate
            
            
            5.00
            %
            
            5.00
            %
            
            5.00
            %
            
            5.00
            %Expected
                Life Based onPrior
                Experience (In Years)
            
            
            5
            
            
            3
                to 7
            
            
            5
            
            
            3
                to 7
 
 Expected
      volatilities are based on the historical volatility of the company's common
      stock. The company uses historical data to estimate option exercise and employee
      termination rates within the model and aggregates groups of employees that
      have
      similar historical exercise behavior for valuation purposes. The company has
      historically not paid dividends on its stock. The risk free interest rate is
      computed from the United States Treasury Strips rate using the term over which
      it is anticipated the grant will be exercised. The stock options granted in
      the
      second quarter of 2007 increased stock compensation expense for the second
      quarter and first six months of 2007 by $0.2 million.
 
 The
      following table shows the fair value of restricted stock awards granted during
      the three and six month periods ending June 30, 2007 and 2006:
 
 **Three
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,****2007**
            
            **2006**
            
            **2007**
            
            **2006**Shares
                Granted
            
            
            5,500
            
            
            ---
            
            
            5,500
            
            
            ---Estimated
                Fair Value (In Millions)
            
            $
            0.3
            
            $
            ---
            
            $
            0.3
            
            $
            ---Percentage
                of Shares GrantedExpected
                to be Distributed
            
            
            95
            %
            
            ---
            
            
            95
            %
            
            ---
 
 The
      restricted stock awards granted in the second quarter of 2007 increased stock
      compensation expense for the second quarter and first six months of 2007 by
      $16,000.
 
 8
 **NOTE
      2 - EARNINGS PER SHARE**
 
 Basic
      and
      diluted earnings per share for the three month periods indicated were computed
      as follows:
 
 **Weighted****Income**
            
            **Shares**
            
            **Per-Share****(Numerator)**
            
            **(Denominator)**
            
            **Amount****(In
                thousands except per share amounts)**For
                the Three Months EndedJune
                30, 2007:Basic
                earnings per common share
            
            $
            65,566
            
            
            46,371
            
            $
            1.41Effect
                of dilutive stock optionsand
                restricted stock bonus shares
            
            
            --
            
            
            232
            
            
            --Diluted
                earnings per common share
            
            $
            65,566
            
            
            46,603
            
            $
            1.41For
                the Three Months EndedJune
                30, 2006:Basic
                earnings per common share
            
            $
            74,817
            
            
            46,228
            
            $
            1.62Effect
                of dilutive stock options
            
            
            --
            
            
            215
            
            
            (0.01
            )Diluted
                earnings per common share
            
            $
            74,817
            
            
            46,443
            
            $
            1.61
 
 The
      following options and their average exercise prices were not included in the
      computation of diluted earnings per share for the three months ended June 30,
      2007 and 2006 because the option exercise prices were greater than the average
      market price of the common stock:
 
 **2007**
            
            
            
            **2006**Options
            
            
            29,500
            
            
            
            
            29,500Average
                Exercise Price
            
            $
            62.29
            
            
            
            $
            62.29
 
  9
  
 Basic
      and
      diluted earnings per share for the six month periods indicated were computed
      as
      follows:
 
 **Weighted****Income**
            
            **Shares**
            
            **Per-Share****(Numerator)**
            
            **(Denominator)**
            
            **Amount****(In
                thousands except per share amounts)**For
                the Six Months EndedJune
                30, 2007:Basic
                earnings per common share
            
            $
            130,048
            
            
            46,350
            
            $
            2.81Effect
                of dilutive stock optionsand
                restricted stock bonus shares
            
            
            --
            
            
            223
            
            
            (0.02
            )Diluted
                earnings per common share
            
            $
            130,048
            
            
            46,573
            
            $
            2.79For
                the Six Months EndedJune
                30, 2006:Basic
                earnings per common share
            
            $
            149,730
            
            
            46,214
            
            $
            3.24Effect
                of dilutive stock options
            
            
            --
            
            
            204
            
            
            (0.01
            )Diluted
                earnings per common share
            
            $
            149,730
            
            
            46,418
            
            $
            3.23
 
 The
      following options and their average exercise prices were not included in the
      computation of diluted earnings per share for the six months ended June 30,
      2007
      and 2006 because the option exercise prices were greater than the average market
      price of the common stock:
 
 **2007**
            
            
            
            **2006**Options
            
            
            61,000
            
            
            
            
            29,500Average
                Exercise Price
            
            $
            59.66
            
            
            
            $
            62.29
  10
  
 **NOTE
      3 – ACQUISITION**
 
 On
      June
      5, 2007, the company’s wholly owned subsidiary, Unit Drilling Company, completed
      the acquisition of a privately owned drilling company operating primarily in
      the
      Texas Panhandle. The acquisition included nine drilling rigs, drill pipe and
      collars, a fleet of 11 trucks, an office, shop, equipment yard and
      personnel.  The drilling rigs range from 800 horsepower to 1,000
      horsepower with depth capacities rated from 10,000 to 15,000
      feet.  Seven of the nine drilling rigs were operating on the
      acquisition date. One drilling rig is being refurbished and should be
      operational during the third quarter of 2007.  Results of operations
      for the acquired company are included in the company’s statement of income
      beginning June 5, 2007.  The total purchase price paid in this
      acquisition (excluding working capital) was allocated as follow (in
      thousands):
 
 
 Drilling
                Rigs
            
            $
            39,326Spare
                Drilling Equipment
            
            
            1,613Drill
                Pipe and Collars
            
            
            7,784Trucks
            
            
            1,551Other
                Vehicles
            
            
            190Yard
                and Office
            
            
            846Goodwill
            
            
            5,548Deferred
                Income Taxes
            
            
            (18,358
            )Total
                Consideration
            
            $
            38,500
 
 An
      additional settlement for working capital will be made in the third quarter
      of
      2007. This settlement is not expected to be material.
 
 **NOTE
      4 – LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES**
 
 As
      of
      June 30, 2007 and December 31, 2006, long-term debt consisted of the
      following:
 
 **June
                30,**
            
            **December
                31,****2007**
            
            **2006****(In
                thousands)**Revolving
                Credit Facility,with
                Interest at June 30, 2007 andDecember
                31, 2006 of 6.5% and 6.4%**,**Respectively
            
            $
            209,800
            
            $
            174,300Less
                Current Portion
            
            
            ---
            
            
            ---Total
                Long-Term Debt
            
            $
            209,800
            
            $
            174,300
 
 On
      May
      24, 2007, the company entered into a First Amended and Restated Senior Credit
      Agreement (Credit Facility) with a maximum credit amount of $400.0 million
      maturing on May 24, 2012. Borrowings under the Credit Facility are limited
      to a
      commitment amount elected by the company. As of June 30, 2007, the current
      commitment amount was $275.0 million. The
      company is
      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
      the total borrowing base amount. The company incurred origination, agency and
      syndication fees of $737,500 at the inception of the Credit
      Facility.  These fees are being amortized over the remaining life of
      the agreement. The average interest rate for the second quarter and first six
      months of 2007 was 6.5%. At June 30, 2007 and July 31, 2007, borrowings were
      $209.8 million and $197.8 million, respectively.
 
 11
 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 the company’s 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
      the company between each scheduled re-determination date and additional
      redeterminations may be requested by the borrowers 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
      the
      company’s 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
      the 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 of the company's
      borrowings 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 the company’s 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 the company’s property, except in
                favor of the company’s lenders.
 
 The
      Credit Facility also requires that the company 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, the company was in compliance with the covenants of the Credit
      Facility.
 
 Other
      long-term liabilities consisted of the following:
  **June
                30,**
            
            
            **December
                31,****2007**
            
            
            **2006****(In
                thousands)**Separation
                Benefit Plans
            
            $
            3,999
            
            $
            3,516Deferred
                Compensation Plan
            
            
            2,829
            
            
            2,544Retirement
                Agreement
            
            
            1,059
            
            
            1,386Workers’
                Compensation
            
            
            22,503
            
            
            22,157Gas
                Balancing Liability
            
            
            1,080
            
            
            1,080Plugging
                Liability
            
            
            34,419
            
            
            33,69265,889
            
            
            64,375Less
                Current Portion
            
            
            10,461
            
            
            8,634Total
                Other Long-Term Liabilities
            
            $
            55,428
            
            $
            55,741
  12
 Estimated
      annual principle payments under the terms of long-term debt and other long-term
      liabilities for the twelve month periods beginning July 1, 2007 through 2010
      are
      $10.5 million, $4.1 million, $1.9 million, $2.3 million and $2.4 million. Based
      on the borrowing rates currently available to the company for debt with similar
      terms and maturities, long-term debt at June 30, 2007 approximates its fair
      value.
 
 
 **NOTE
      5 – ASSET RETIREMENT OBLIGATIONS**
 
 Under
      Financial Accounting Standards No. 143, “Accounting for Asset Retirement
      Obligations”**(FAS 143) the company must record the fair value of
      liabilities associated with the retirement of long-lived assets. The company
      owns oil and natural gas properties which require cash to plug and abandon
      the
      wells when the oil and natural gas reserves in the wells are depleted or the
      wells are no longer able to produce. These expenditures under FAS 143 are
      recorded in the period in which the liability is incurred (at the time the
      wells
      are drilled or acquired). The company does not have any assets restricted
      for the purpose of settling these plugging liabilities.
 
 The
      following table shows the activity for the six months ending June 30, 2007
      and
      2006 relating to the company’s retirement obligation for plugging
      liability:
 
 
 **Six
                Months Ended****2007**
            
            **2006****(In
                Thousands)**Plugging
                Liability, January 1:
            
            $
            33,692
            
            $
            22,015Accretion
                of Discount
            
            
            889
            
            
            696Liability
                Incurred
            
            
            786
            
            
            1,867Liability
                Settled
            
            
            (1,113
            )
            
            (101
            )Revision
                of Estimates
            
            
            165
            
            
            6,984Plugging
                Liability, June 30
            
            
            34,419
            
            
            31,461Less
                Current Portion
            
            
            1,629
            
            
            607Total
                Long-Term Plugging Liability
            
            $
            32,790
            
            $
            30,854
 
 
 **NOTE
      6 - NEW ACCOUNTING PRONOUNCEMENTS**
 
 In
      June 2006, the Financial Accounting
      Standards Board (“FASB“) issued FASB Interpretation No. 48, "Accounting for
      Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109" (FIN
      48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized
      in an enterprise’s financial statements in accordance with FAS No. 109,
      "Accounting for Income Taxes" and prescribes a recognition threshold and
      measurement attribute for the financial statement recognition and measurement
      of
      a tax position taken or expected to be taken in a return. Guidance is also
      provided on de-recognition, classification, interest and penalties, accounting
      in interim periods, disclosure and transition. The company adopted the
      provisions of FIN 48 effective January 1, 2007. The company has no
      unrecognized tax benefits and the adoption of FIN 48 had no effect on the
      company's results of operations or financial condition and we do not expect
      any
      significant changes in unrecognized tax benefits in the next twelve
      months.
 
 In
      June
      2006, the FASB ratified the consensuses reached by the Emerging Issues Task
      Force on EITF 06-3, "How Taxes Collected from Customers and Remitted to
      Governmental Authorities Should Be Presented in the Income Statement (That
      is,
      Gross versus Net Presentation".) which became effective for the company on
      January 1, 2007. According to the provisions of EITF 06-3:
  ·  
                taxes assessed by a governmental authority that are directly imposed
                on a
                revenue-producing transaction between a seller and a customer may
                include,
                but are not limited to, sales, use, value added, and some excise
                taxes;
                and
   13
  ·  
                that the presentation of such taxes on either a gross (included in
                revenues and costs) or a net (excluded from revenues) basis is an
                accounting policy decision that should be disclosed under Accounting
                Principles Board Opinion No. 22 (as amended), "Disclosure of Accounting
                Policies." In addition, for any such taxes that are reported on a
                gross
                basis, a company should disclose the amounts of those taxes in interim
                and
                annual financial statements for each period for which an income statement
                is presented if those amounts are significant. The disclosure of
                those
                taxes can be made on an aggregate
                basis.
  Because
      the provisions of EITF 06-3 require only the presentation of additional
      disclosures, the adoption of EITF 06-3 did not have an effect on the company's
      statements of income, financial condition or cash flows. The company collects
      sales and use tax when it sells used equipment or rents drilling equipment
      to
      third parties. The sales and use tax is reported net.  Gross
      production taxes associated with the sale of oil and natural gas production
      is
      reported on a gross basis and was $12.1 million for the first six months of
      2007
      and $11.0 million for the first six months of 2006.
 
 In
      September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (FAS
      157). FAS 157 establishes a common definition for fair value to be applied
      to US
      GAAP guidance requiring use of fair value, establishes a framework for measuring
      fair value, and expands the disclosure about such fair value measurements.
      FAS
      157 is effective for fiscal years beginning after November 15, 2007. The company
      is currently assessing the impact of FAS 157 on its statement of income,
      financial condition and cash flows.
 
 In
      February 2007, the FASB issued FAS No. 159, “The Fair Value Option for
      Financial Assets and Financial Liabilities — Including an amendment of FASB
      Statement No. 115”, (FAS 159) which permits entities to choose to measure
      many financial instruments and certain other items at fair value at specified
      election dates. A business entity is required to report unrealized gains and
      losses on items for which the fair value option has been elected in earnings
      at
      each subsequent reporting date. This statement is expected to expand the use
      of
      fair value measurement. FAS 159 is effective for financial statements issued
      for
      fiscal years beginning after November 15, 2007, and interim periods within
      those fiscal years, and is applicable beginning in the first quarter of 2008.
      The company is currently assessing the impact of FAS 159 on its statement of
      income, financial condition and cash flows.
 
 
 **NOTE
      7 – GOODWILL**
 
 Goodwill
      represents the excess of the cost of  acquisitions over the fair value
      of the net assets acquired. Goodwill of $5.5 million was added from the
      acquisition completed in the second quarter of 2007. An annual impairment test
      is performed in the fourth quarter of each year to determine whether the fair
      value has decreased and additionally when events indicate an impairment may
      have
      occurred. Goodwill is all related to the company’s drilling
      segment.
 
  14
  
 **NOTE
      8 – HEDGING ACTIVITY**
 
 The
      company periodically enters into derivative commodity instruments to hedge
      its
      exposure to the fluctuations in the prices it receives for its oil and natural
      gas production and mid-stream activities. These instruments include regulated
      natural gas and crude oil futures contracts traded on the New York Mercantile
      Exchange (NYMEX) and over-the-counter swaps and basic hedges with major energy
      derivative product specialists.
 
 In
      June
      2007, the company entered into natural gas liquids sales swaps and natural
      gas
      purchase swaps to lock in a percentage of the company’s 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 ConwayPropane
            396,690
                gal./month
            $
                1.1475
            OPIS
                Propane ConwayPropane
            396,690
                gal./month
            $
                1.15
            OPIS
                Propane ConwayIso
                Butane
            61,782
                gal./month
            $
                1.2625
            OPIS
                Iso Butane ConwayIso
                Butane
            61,782
                gal./month
            $
                1.2975
            OPIS
                Iso Butane ConwayNormal
                Butane
            163,632
                gal./month
            $
                1.2975
            OPIS
                Normal Butane ConwayNormal
                Butane
            163,632
                gal./month
            $
                1.27
            OPIS
                Normal Butane ConwayNatural
                Gasoline
            411,012
                gal./month
            $
                1.7375
            OPIS
                Nat. Gas Conway In-WellNatural
                Gas
            107,710
                MMBtu/month
            $
                7.00
            IF
                PEPL Natural GasNatural
                Gas
            107,710
                MMBtu/month
            $
                7.04
            IF
                PEPL Natural Gas
 
 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, the company entered into the following two natural
      gas collar contracts:
 
 **First
                Contract:**Production
                volume covered
            10,000
                MMBtu/dayPeriod
                covered
            May
                through December of 2007Prices
            Floor
                of $6.00 and a ceiling of $10.00Underlying
                commodity price
            Centerpoint
                Energy Gas Transmission Co.,East
                – Inside FERC**Second
                Contract:**Production
                volume covered
            10,000
                MMBtu/dayPeriod
                covered
            March
                through December of 2007Prices
            Floor
                of $6.25 and a ceiling of $9.25Underlying
                commodity price
            Centerpoint
                Energy Gas Transmission Co.,East
                – Inside FERC
 
 In
      December 2006, the company also entered into the following natural gas hedging
      transaction:
  **Contract:**Production
                  volume covered
              10,000
                  MMBtu/dayPeriod
                  covered
              January through
                  December of 2007Prices
              Floor
                  of $6.00 and a ceiling of $9.60Underlying
                  commodity price
              Centerpoint
                  Energy Gas Transmission Co.,East
                  – Inside FERC
 15
 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.
 
 In
      February 2005, the company entered into an interest rate swap to help manage
      its
      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,
      in
      the second quarter and first six months of 2007 the company's interest expense
      was decreased by $0.2 million and $0.3 million, respectively.  The
      company’s interest expense was decreased by $0.1 million in the second quarter
      of 2006 and $0.2 million for the six months ended June 30, 2006. 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.
 
 
 **NOTE
      9 - INDUSTRY SEGMENT INFORMATION**
 
 The
      company has three business segments:
 
 .    Contract
      Drilling,
 .    Oil
      and Natural Gas and
 .    Mid-Stream
 
 These
      three segments represent the company's three main business units offering
      different products and services. The Contract Drilling segment is engaged in
      the
      land contract drilling of oil and natural gas wells, the Oil and Natural Gas
      segment is engaged in the development, acquisition and production of oil and
      natural gas properties and the Mid-Stream segment is engaged in the buying,
      selling, gathering, processing and treating of natural gas.
  16
  
 The
      company evaluates the performance of these operating segments based on operating
      income, which is defined as operating revenues less operating expenses and
      depreciation, depletion and amortization. The company has natural gas production
      in Canada, which is not significant. Information regarding the company’s
      operations by segment for the three and six month periods ended June 30, 2007
      and 2006 is as follows:
 
 **Three
                Months Ended**
            
            
            
            **Six
                Months Ended****June
                30,**
            
            
            
            **June
                30,****2007**
            
            **2006**
            
            
            
            **2007**
            
            **2006****(In
                thousands)**Revenues:Contract
                drilling
            
            $
            164,987
            
            $
            185,793
            
            
            
            $
            333,800
            
            $
            353,475Elimination
                of inter-segmentrevenue
            
            
            10,638
            
            
            9,885
            
            
            
            
            19,166
            
            
            16,137Contract
                drilling net ofinter-segment
                revenue
            
            
            154,349
            
            
            175,908
            
            
            
            
            314,634
            
            
            337,338Oil
                and natural gas
            
            
            96,343
            
            
            81,954
            
            
            
            
            182,449
            
            
            176,280Gas
                gathering and processing
            
            
            38,935
            
            
            25,020
            
            
            
            
            72,866
            
            
            54,258Elimination
                of inter-segmentrevenue
            
            
            3,166
            
            
            3,300
            
            
            
            
            6,329
            
            
            7,056Gas
                gathering and processingnet
                of inter-segment revenue
            
            
            35,769
            
            
            21,720
            
            
            
            
            66,537
            
            
            47,202Other
                (1)
            
            
            179
            
            
            767
            
            
            
            
            291
            
            
            2,337Total
                revenues
            
            $
            286,640
            
            $
            280,349
            
            
            
            $
            563,911
            
            $
            563,157Operating
                Income (2):Contract
                drilling
            
            $
            65,938
            
            $
            83,946
            
            
            
            $
            137,219
            
            $
            153,226Oil
                and natural gas
            
            
            41,159
            
            
            37,925
            
            
            
            
            75,779
            
            
            89,763Gas
                gathering and processing
            
            
            1,819
            
            
            1,771
            
            
            
            
            2,747
            
            
            3,302Total
                operating income
            
            
            108,916
            
            
            123,642
            
            
            
            
            215,745
            
            
            246,291General
                and administrativeexpense
            
            
            (5,247
            )
            
            (4,402
            )
            
            
            
            (10,429
            )
            
            (8,368
            )Interest
                expense
            
            
            (1,729
            )
            
            (1,017
            )
            
            
            
            (3,370
            )
            
            (2,007
            )Other
                income - net
            
            
            179
            
            
            767
            
            
            
            
            291
            
            
            2,337Income
                before incometaxes
            
            $
            102,119
            
            $
            118,990
            
            
            
            $
            202,237
            
            $
            238,253
   (1)
              Includes
                    a $1.0 million gain from insurance proceeds on the loss of a
                    drilling rig
                    from a blow out and fire in January 2006.
 (2)
            Operating
                income is total operating revenues less operating expenses, depreciation,
                depletion and amortization and does not include non-operating revenues,
                general corporate expenses, interest expense or income
                taxes.
  17
  **REPORT
      OF INDEPENDENT REGISTERED
      PUBLIC ACCOUNTING FIRM**
 
 
 
 To
      the
      Board of Directors and Shareholders
 Unit
      Corporation
 
 We
      have
      reviewed the accompanying consolidated condensed balance sheet of Unit
      Corporation and its subsidiaries as of June 30, 2007, and the related
      consolidated condensed statements of income and comprehensive income for each
      of
      the three-month and six-month periods ended June 30, 2007 and 2006 and the
      consolidated condensed statements of cash flows for the six-month periods ended
      June 30, 2007 and 2006. These interim financial statements are the
      responsibility of the company’s management.
 
 We
      conducted our review in accordance with standards of the Public Company
      Accounting Oversight Board (United States). A review of interim financial
      information consists principally of applying analytical procedures and making
      inquiries of persons responsible for financial and accounting matters. It is
      substantially less in scope than an audit conducted in accordance with the
      standards of the Public Company Accounting Oversight Board (United States),
      the
      objective of which is the expression of an opinion regarding the financial
      statements taken as a whole. Accordingly, we do not express such an
      opinion.
 
 Based
      on
      our review, we are not aware of any material modifications that should be made
      to the accompanying consolidated condensed interim financial statements for
      them
      to be in conformity with accounting principles generally accepted in the United
      States of America.
 
 We
      previously audited, in accordance with the standards of the Public Company
      Accounting Oversight Board (United States), the consolidated balance sheet
      as of
      December 31, 2006, and the related consolidated statements of income,
      shareholders’ equity and of cash flows for the year then ended (not presented
      herein), and in our report dated March 1, 2007 we expressed an unqualified
      opinion on those consolidated financial statements. In our opinion, the
      information set forth in the accompanying consolidated condensed balance sheet
      as of December 31, 2006, is fairly stated in all material respects in relation
      to the consolidated balance sheet from which it has been derived.
 
 
 PricewaterhouseCoopers
      LLP
 
 
 Tulsa,
      Oklahoma
 August
      2,
      2007
  18
  **Item
      2.  Management’s Discussion and Analysis of Financial Condition and
      Results of Operations**
 
 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 receivefor 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 TexasDrilling,
                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.
   19
  
 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 Total Capitalization
            
            
            14
            %
            
            12
            %
            
            17
            %Net
                Income
            
            $
            130,048
            
            $
            149,730
            
            
            (13
            )%Net
                Cash From Operating Activities
            
            $
            219,352
            
            $
            223,485
            
            
            (2
            )%Net
                Cash Used in Investing Activities
            
            $
            (258,753
            )
            $
            (210,407
            )
            
            23
            %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 Excluding Hedges
            
            $
            50.66
            
            $
            55.88
            
            
            (9
            )%Average
                Natural Gas Price Received
            
            $
            6.58
            
            $
            6.41
            
            
            3
            %Average
                Natural Gas Price Received Excluding Hedges
            
            $
            6.57
            
            $
            6.41
            
            
            2
            %Average
                Number of Our Drilling Rigs in Use Duringthe
                Period
            
            
            97.4
            
            
            109.5
            
            
            (11
            )%Total
                Number of Drilling Rigs Available at the Endof
                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 Gathering Systems
            
            
            37
            
            
            37
            
            
            ---
            %Number
                of Active Processing Systems
            
            
            7
            
            
            6
            
            
            17
            %
  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
   20
 
 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.
 
  21
  ***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 andEquipment
                Purchases (4)
            
            
            
            
            19,071
            
            
            19,071
            
            
            ---
            
            
            ---
            
            
            ---Total
                ContractualObligations
            
            
            
            $
            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.
 
  22
  
 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
                CompensationAgreement
                (1)
            
            
            
            
            
            $
            2,829
            
            
            Unknown
            
            
            Unknown
            
            
            Unknown
            
            
            UnknownSeparation
                BenefitAgreement
                (2)
            
            
            
            
            
            $
            3,999
            
            
            Unknown
            
            
            Unknown
            
            
            Unknown
            
            
            UnknownPlugging
                Liability (3)
            
            
            
            
            
            $
            34,419
            
            $
            1,629
            
            $
            1,558
            
            $
            3,188
            
            $
            28,044Gas
                BalancingLiability
                (4)
            
            
            
            
            
            $
            1,080
            
            
            Unknown
            
            
            Unknown
            
            
            Unknown
            
            
            UnknownRepurchaseObligations
                (5)
            
            
            
            
            
            
            Unknown
            
            
            Unknown
            
            
            Unknown
            
            
            Unknown
            
            
            UnknownWorkers’
                CompensationLiability
                (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
   23
  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 ConwayPropane
            396,690
                gal./month
            $
                1.1475
            OPIS
                Propane ConwayPropane
            396,690
                gal./month
            $
                1.15
            OPIS
                Propane ConwayIso
                Butane
            61,782
                gal./month
            $
                1.2625
            OPIS
                Iso Butane ConwayIso
                Butane
            61,782
                gal./month
            $
                1.2975
            OPIS
                Iso Butane ConwayNormal
                Butane
            163,632
                gal./month
            $
                1.2975
            OPIS
                Normal Butane ConwayNormal
                Butane
            163,632
                gal./month
            $
                1.27
            OPIS
                Normal Butane ConwayNatural
                Gasoline
            411,012
                gal./month
            $
                1.7375
            OPIS
                Nat. Gas Conway In-WellNatural
                Gas
            107,710
                MMBtu/month
            $
                7.00
            IF
                PEPL Natural GasNatural
                Gas
            107,710
                MMBtu/month
            $
                7.04
            IF
                PEPL Natural Gas
 
 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/dayPeriod
                covered
            May
                through December of 2007Prices
            Floor
                of $6.00 and a ceiling of $10.00Underlying
                commodity price
            Centerpoint
                Energy Gas Transmission Co.,East
                – Inside FERC**Second
                Contract:**Production
                volume covered
            10,000
                MMBtu/dayPeriod
                covered
            March
                through December of 2007Prices
            Floor
                of $6.25 and a ceiling of $9.25Underlying
                commodity price
            Centerpoint
                Energy Gas Transmission Co.,East
                – Inside FERC
 
  24
  In
      December 2006, we entered into the following natural gas collar
      contract:
 **Contract:**Production
                    volume covered
                10,000
                    MMBtu/dayPeriod
                    covered
                January through
                    December of 2007Prices
                Floor
                    of $6.00 and a ceiling of $9.60Underlying
                    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.
 
 25
 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
      second quarter of 2006 provided pay increases in some of our operating
      districts. To date, these efforts have allowed us to meet our labor
      requirements. However, if current demand for drilling rigs strengthens above
      the
      first six month levels of 82%, shortages of experienced personnel may limit
      our
      ability to operate our drilling rigs.
  We
      currently do not have any shortages of drill pipe and drilling equipment.
      Because of the potential for shortages in the availability of new drill pipe,
      at
      June 30, 2007 we have commitments to purchase approximately $16.6 million of
      drill pipe and drill collars in 2007 and we have also committed to purchase
      $3.1
      million of additional rig components with 20% or a $0.6 million paid through
      June 30, 2007.  We are refurbishing a drilling rig acquired in the
      second quarter 2007 drilling acquisition which should be placed in service
      in
      the third quarter of 2007 and one additional rig is scheduled to be placed
      in
      service in the fourth quarter of 2007.
  Most
      of
      our contract drilling fleet is targeted to the drilling of natural gas wells
      so
      changes in natural gas prices have a disproportionate influence on the demand
      for our drilling rigs as well as the prices we can charge for our contract
      drilling services. In June 2007, our average dayrate for the 128 drilling rigs
      that we owned was $18,637 with an 80% utilization rate. In the first six months
      of 2007 our average dayrate was $19,062 per day compared to $17,870 in the
      first
      six months of 2006. The average number of drilling rigs used was 97.4 (82%)
      in
      the first six months of 2007 compared to 109.5 (98%) in the first six months
      of
      2006. Based on the average utilization of our drilling rigs during the first
      six
      months of 2007, a $100 per day change in dayrates has a $9,740 per day ($3.6
   26
 
 million
        annualized) change in our pre-tax operating cash flow. Industry demand for
        our
        drilling rigs remained strong throughout the first nine months of 2006 before
        declining in the fourth quarter of 2006 and into the first six months of
        2007.  The reduction in demand for drilling rigs was primarily the
        result of the evaluation of the economics of drilling prospects by the operators
        using our contract drilling services after natural gas prices declined
        significantly in the last half of the third quarter of 2006 combined with
        high
        levels of natural gas storage throughout the majority of the winter season.
        We
        expect that utilization and dayrates for our drilling rigs will continue
        to
        depend mainly on the price of natural gas, the levels of natural gas storage
        and
        the availability of drilling rigs to meet the demands of the
        industry.
 
 Our
      contract drilling subsidiaries provide drilling services for our exploration
      and
      production subsidiary. The contracts for these services are issued under the
      same conditions and rates as the contracts we have entered into with unrelated
      third parties for comparable type projects. During the first six months of
      2007
      and 2006, we drilled 32 and 29 wells, respectively for our exploration and
      production subsidiary. The profit received by our contract drilling segment
      of
      $9.9 million and $8.6 million during the first six months of 2007 and 2006,
      respectively, reduced the carrying value of our oil and natural gas properties
      rather than being included in our profits in current operations.
 
 ***Drilling Acquisitions and Capital Expenditures.***  In
      January 2006, we acquired a 1,000 horsepower drilling rig for approximately
      $3.9
      million. This drilling rig has been modified at one of our drilling yards for
      an
      additional $1.7 million and became operational in April 2006.  In May
      2006, we began moving a 1,500 horsepower drilling rig to our Rocky Mountain
      Division following completion of its construction in the first quarter of 2006
      for approximately $10.2 million. In the second quarter of 2006, we also
      completed the purchase of two new 1,500 horsepower drilling rigs for a total
      of
      $15.2 million of which $4.6 million was paid before the second quarter of 2006
      and the balance of $10.6 million was paid at delivery of the rigs. An additional
      $3.0 million of modifications were made to the rigs before the rigs were placed
      into service. The first drilling rig was placed into service in May 2006 and
      the
      second drilling rig was placed into service in June 2006. At the end of August
      2006 we completed the construction of another 1,500 horsepower rig for
      approximately $9.5 million which was moved into our Rocky Mountain Division.
      In
      the last half of 2006 we completed construction of a 750 horsepower rig for
      approximately $4.5 million.
  During
      2006 we paid $4.5 million for the purchase of major components to construct
      two
      1,500 horsepower drilling rigs. The first rig was being moved to the Rocky
      Mountain division at the end of March 2007 and was constructed for approximately
      $9.6 million. The second rig was placed in service in the second quarter of
      2007
      and was constructed for approximately $7.6 million. On June 5, 2007, we
      completed the acquisition of a privately owned drilling company operating
      primarily in the Texas Panhandle. The acquired drilling company owns nine
      drilling rigs, a fleet of 11 trucks, and an office, shop and equipment
      yard.  The drilling rigs range from 800 horsepower to 1,000 horsepower
      with depth capacities rated from 10,000 to 15,000 feet.  Seven of the
      nine drilling rigs were operating under contract at the acquisition
      date.  Results of operations for the acquired company are included in
      the company’s statement of income beginning June 5, 2007.  Total
      consideration paid for this acquisition was $38.5 million.
 
 For
      our
      contract drilling operations, during the first six months of 2007, we recorded
      $147.2 million in capital expenditures including the effect of an $18.4 million
      deferred tax liability and $5.5 million in goodwill associated with our second
      quarter 2007 acquisition. For the year 2007, we have budgeted capital
      expenditures of approximately $131.0 million excluding
      acquisitions.
 
 ***Mid-Stream
      Operations***.    Our mid-stream operations
      are conducted through Superior Pipeline Company, L.L.C. and its subsidiary.
      Superior is a mid-stream company engaged primarily in the buying and selling,
      gathering, processing and treating of natural gas and operates four natural
      gas
      treatment plants, seven operating processing plants, 37 active gathering systems
      and 641 miles of pipeline. Superior operates in Oklahoma, Texas, Louisiana
      and
      Kansas and has been in business since 1996. This subsidiary enhances our ability
      to gather and market not only our own natural gas but also that owned by third
      parties and gives us additional capacity to construct or acquire existing
      natural gas gathering and processing facilities.  During the first six
      months of 2007, Superior purchased $3.9 million of our natural gas production
      and natural gas liquids and provided gathering and transportation services
      of
      $2.4 million. Intercompany revenue from services and purchases of production
      between this business segment and our oil and natural gas exploration operations
      has been eliminated in our consolidated condensed financial statements. In
      the
      first six months of 2006, we eliminated intercompany revenues of $4.5 million
      of
      natural gas and $2.6 million of natural gas liquids.
   27
 ***Mid-Stream
      Acquisitions and Capital Expenditures.***  In September
      2006, we closed the acquisition of Berkshire Energy LLC., a private company
      for
      an adjusted purchase price of $21.7 million.  The principal tangible
      assets of the acquired company consisted of a natural gas processing plant,
      a
      natural gas gathering system with 15 miles of pipeline, three field compressors
      and two plant compressors.  This purchase had an effective date of
      July 31, 2006. The financial results of this acquisition are included in the
      company's statement of income from September 1, 2006 forward with the results
      for the period of August 1, 2006 through August 31, 2006 included as an
      adjustment to the purchase price.
 
 During
      the first six months of 2007, Superior incurred $18.0 million in capital
      expenditures compared to $10.0 million for the same period in 2006. For 2007,
      we
      have budgeted capital expenditures of approximately $25.0 million for Superior.
      Our focus is on growing this segment through the construction of new facilities
      or acquisitions.
 
 ***Oil and Natural Gas Limited Partnerships and Other Entity
      Relationships******.***We are the general
      partner for 12 oil and natural gas limited partnerships. Each partnership’s
      revenues and costs are shared under formulas prescribed in its limited
      partnership agreement. The partnerships repay us for contract drilling, well
      supervision and general and administrative expense. Related party transactions
      for contract drilling and well supervision fees are the related party’s share of
      such costs. These costs are billed on the same basis as billings to unrelated
      third parties for similar services. General and administrative reimbursements
      consist of direct general and administrative expense incurred on the related
      party’s behalf as well as indirect expenses assigned to the related parties.
      Allocations are based on the related party’s level of activity and are
      considered by management to be reasonable. During 2006, the total paid to us
      for
      all of these fees was $1.3 million and we expect the amount to approximately
      be
      the same in 2007. Our proportionate share of assets, liabilities and net income
      relating to the oil and natural gas partnerships is included in our consolidated
      condensed financial statements.
 
  28
  **NEW ACCOUNTING PRONOUNCEMENTS**
 
 In
      June
      2006, the Financial Accounting Standards Board (“FASB“) issued FASB
      Interpretation No. 48, "Accounting for Uncertainty in Income Taxes, an
      Interpretation of FASB Statement No. 109" (FIN 48). FIN 48 clarifies the
      accounting for uncertainty in income taxes recognized in an enterprise’s
      financial statements in accordance with FAS No. 109, "Accounting for Income
      Taxes" and prescribes a recognition threshold and measurement attribute for
      the
      financial statement recognition and measurement of a tax position taken or
      expected to be taken in a return. Guidance is also provided on de-recognition,
      classification, interest and penalties, accounting in interim periods,
      disclosure and transition. We adopted the provisions of FIN 48 effective
      January 1, 2007. We have no unrecognized tax benefits and the adoption of
      FIN 48 had no effect on our results of operations of financial condition and
      we
      do not expect any significant changes in unrecognized tax benefits in the next
      twelve months.
 
 In
      June
      2006, the FASB ratified the consensuses reached by the Emerging Issues Task
      Force on EITF 06-3, "How Taxes Collected from Customers and Remitted to
      Governmental Authorities Should Be Presented in the Income Statement (That
      is,
      Gross versus Net Presentation".) which became effective for us on January 1,
      2007. According to the provisions of EITF 06-3:
  ·  
                taxes assessed by a governmental authority that are directly imposed
                on a
                revenue-producing transaction between a seller and a customer may
                include,
                but are not limited to, sales, use, value added, and some excise
                taxes;
                and
  ·  
                that the presentation of such taxes on either a gross (included in
                revenues and costs) or a net (excluded from revenues) basis is an
                accounting policy decision that should be disclosed under Accounting
                Principles Board Opinion No. 22 (as amended), "Disclosure of Accounting
                Policies." In addition, for any such taxes that are reported on a
                gross
                basis, a company should disclose the amounts of those taxes in interim
                and
                annual financial statements for each period for which an income statement
                is presented if those amounts are significant. The disclosure of
                those
                taxes can be made on an aggregate
                basis.
  Because
      the provisions of EITF 06-3 require only the presentation of additional
      disclosures, the adoption of EITF 06-3 did not have an effect on our statements
      of income, financial condition or cash flows. We collect sales and use tax
      when
      we sell used equipment or rent drilling equipment to third parties. The sales
      and use tax is reported net.  Gross production taxes associated with
      the sale of oil and natural gas production is reported gross and was $12.1
      million for the first six months of 2007 and $11.0 million for the first six
      months of 2006.
 
 In
      September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” (FAS
      157). FAS 157 establishes a common definition for fair value to be applied
      to US
      GAAP guidance requiring use of fair value, establishes a framework for measuring
      fair value, and expands the disclosure about such fair value measurements.
      FAS
      157 is effective for fiscal years beginning after November 15, 2007. We are
      currently assessing the impact of FAS 157 on our statement of income, financial
      condition and cash flows.
 
 In
      February 2007, the FASB issued FAS No. 159, “The Fair Value Option for
      Financial Assets and Financial Liabilities — Including an amendment of FASB
      Statement No. 115”, (FAS 159) which permits entities to choose
      to measure many financial instruments and certain other items at fair value
      at
      specified election dates. A business entity is required to report unrealized
      gains and losses on items for which the fair value option has been elected
      in
      earnings at each subsequent reporting date. This statement is expected to expand
      the use of fair value measurement.FAS 159 is effective for
      financial statements issued for fiscal years beginning after November 15,
      2007, and interim periods within those fiscal years, and is applicable beginning
      in the first quarter of 2008. We are currently assessing the impact of FAS
      159
      on our statement of income, financial condition and cash flows.
  29
  **RESULTS
      OF
      OPERATIONS**
 
 **Quarter
      Ended June 30, 2007 versus Quarter Ended June 30, 2006**
 
 Provided
      below is a comparison of selected operating and financial data for the second
      quarter of 2007 versus the second quarter of 2006:
 
 **Quarter
                Ended**
            
            **Quarter
                Ended****June
                30,**
            
            **June
                30,**
            
            **Percent****2007**
            
            **2006**
            
            **Change**Total
                Revenue
            
            
            
            $
            286,640,000
            
            $
            280,349,000
            
            2
            %Net
                Income
            
            
            
            $
            65,566,000
            
            $
            74,817,000
            
            (12
            )%**Drilling:**Revenue
            
            
            
            $
            154,349,000
            
            $
            175,908,000
            
            (12
            )%Operating
                costs excluding depreciation
            
            
            
            $
            74,729,000
            
            $
            79,117,000
            
            (6
            )%Percentage
                of revenue fromdaywork
                contracts
            
            
            
            
            100
            %
            
            100
            %
            ---Average
                number of rigs in use
            
            
            
            
            97.9
            
            
            110.3
            
            (11
            )%Average
                dayrate on dayworkcontracts
            
            
            
            $
            18,710
            
            $
            18,588
            
            1
            %Depreciation
            
            
            
            $
            13,682,000
            
            $
            12,845,000
            
            7
            %**Oil
                and Natural Gas:**Revenue
            
            
            
            $
            96,343,000
            
            $
            81,954,000
            
            18
            %Operating
                costs excluding depreciation,depletion
                and amortization
            
            
            
            $
            24,461,000
            
            $
            18,988,000
            
            29
            %Average
                natural gas price (Mcf)
            
            
            
            $
            6.78
            
            $
            5.76
            
            18
            %Average
                oil price (Bbl)
            
            
            
            $
            53.18
            
            $
            57.11
            
            (7
            )%Natural
                gas production (Mcf)
            
            
            
            
            10,628,000
            
            
            10,438,000
            
            2
            %Oil
                production (Bbl)
            
            
            
            
            433,000
            
            
            359,000
            
            21
            %Depreciation,
                depletion andamortization
                rate (Mcfe)
            
            
            
            $
            2.31
            
            $
            1.98
            
            17
            %Depreciation,
                depletion andamortization
            
            
            
            $
            30,723,000
            
            $
            25,041,000
            
            23
            %**Gas
                Gathering and Processing:**Revenue
            
            
            
            $
            35,769,000
            
            $
            21,720,000
            
            65
            %Operating
                costs excluding depreciationand
                amortization
            
            
            
            $
            31,395,000
            
            $
            18,717,000
            
            68
            %Depreciation
                and amortization
            
            
            
            $
            2,555,000
            
            $
            1,232,000
            
            107
            %Gas
                gathered – MMbtu/day
            
            
            
            
            218,290
            
            
            243,399
            
            (10
            )%Gas
                processed – MMbtu/day
            
            
            
            
            42,645
            
            
            31,000
            
            38
            %Gas
                liquids sold – Gallons/day
            
            
            
            
            113,829
            
            
            50,169
            
            127
            %General
                and Administrative Expense
            
            
            
            $
            5,247,000
            
            $
            4,402,000
            
            19
            %Interest
                Expense
            
            
            
            $
            1,729,000
            
            $
            1,017,000
            
            70
            %Income
                Tax Expense
            
            
            
            $
            36,553,000
            
            $
            44,173,000
            
            (17
            )%Average
                Interest Rate
            
            
            
            
            6.11
            %
            
            5.78
            %
            6
            %Average
                Long-Term Debt Outstanding
            
            
            
            $
            179,192,000
            
            $
            118,220,000
            
            52
            %
 
 Industry
      demand for our drilling rigs remained strong throughout the first nine months
      of
      2006 before declining in the fourth quarter of 2006 and into the first six
      months of 2007. The reduction in demand for drilling rigs was primarily the
      result of the evaluation of the economics of drilling prospects by the operators
      using our
  30
 
 contract
        drilling services after natural gas prices declined significantly in the
        last
        half of the third quarter of 2006 combined with the high levels of natural
        gas
        storage throughout the majority of the winter season and again this summer.
        Drilling revenues decreased $21.6 million or 12% in the second quarter of
        2007
        versus the second quarter of 2006. Since the first quarter of 2006, we have
        placed 16 additional drilling rigs into service. We have constructed seven
        drilling rigs and in June 2007 we acquired nine drilling rigs. Thirteen of
        these
        additional drilling rigs provided contract drilling services in the second
        quarter of 2007 increasing drilling revenues by $9.8 million or 6% of revenues
        in the second quarter of 2006. Revenues for rigs previously owned declined
        $31.4
        million or 18% of the revenues in the second quarter of 2006 and more than
        offset the increase in revenue from rigs added subsequent to the second quarter
        of 2006. Average rig utilization declined from 110.3 rigs in the second quarter
        of 2006 to 97.9 in the second quarter of 2007. The decline in rig utilization
        decreased drilling revenues by $19.7 million while decreases in revenue per
        day
        between the comparative second quarters decreased revenue by $1.9 million.
        Our
        average dayrate in the second quarter of 2007 was 1% higher than in the second
        quarter of 2006.  Demand for our drilling rigs is anticipated to
        remain in the 80% to 85% range in the short term. With decreases in drilling
        rig
        demand, we experienced a 4% decline in the second quarter 2007 average dayrate
        compared to the first quarter 2007 average dayrate and we expect further
        decreases in average dayrates to continue into the third
        quarter.
  Drilling
      operating costs decreased $4.4 million or 6% between the comparative quarters.
      Operating cost decreased as utilization dropped 12.4 rigs between the
      comparative quarters. Operating cost per day increased $501 in the second
      quarter of 2007 when compared with the second quarter of 2006 and partially
      offset the decrease from reduced operating days. The majority of the increase
      in
      cost per day was attributable to indirect drilling cost for repair supplies
      and
      maintenance and property taxes and to a lesser extent costs directly associated
      with drilling wells. With continued competition for qualified labor and
      utilization continuing at 80% or above, we expect our drilling rig expenses
      per
      day to remain steady or increase slightly over the remainder of 2007. Contract
      drilling depreciation increased $0.8 million or 7%. The addition of the net
      16
      drilling rigs placed in service since the first quarter of 2006 and additional
      assets acquired in the 2007 second quarter rig acquisition increased
      depreciation $0.8 million with the increase partially offset from the effect
      of
      decreased utilization.
 
 Oil
      and
      natural gas revenues increased $14.4 million or 18% in the second quarter of
      2007 as compared to the second quarter of 2006 due to an increase in equivalent
      production volumes of 5% and an increase in average natural gas prices. The
      increases were partially offset by decreased oil prices. Average natural gas
      prices between the comparative quarters increased 18% to $6.78 per Mcf while
      oil
      prices declined 7% to $53.18 per barrel. In the second quarter of 2007, natural
      gas production increased by 2% while oil production increased 21%. Increased
      natural gas and oil production came primarily from our ongoing development
      drilling activity and from acquisitions completed in 2006.  With the
      continuation of our internal drilling program and our previous acquisitions,
      we
      believe our total production for 2007 compared to 2006 will increase 6% to
      10%.
      Actual increases in revenues, however, will also be driven by commodity prices
      received for our production.
 
 Oil
      and natural gas operating costs increased $5.5 million or 29% in the second
      quarter of 2007 as compared to 2006. An increase in the average cost per
      equivalent Mcf produced represented 81% of the increase in production costs
      with
      the remaining 19% of the increase attributable to the increase in volumes
      produced from both development drilling and producing property acquisitions.
      Lease operating expenses represented 69% of the increase, gross production
      taxes
      20%, general and administrative cost directly related to oil and natural gas
      production 10% and increased accretion on plugging liability 1%. Lease operating
      expenses per Mcfe increased 26% between the comparative quarters as post
      production transportation cost, salt water disposal fees and compression
      increased along with a 79% increase in workover cost.  Gross
      production taxes increased due to the increase in oil and natural gas volumes
      produced between the comparative quarters and the increase in natural gas
      prices. General and administrative expenses increased as labor costs increased
      primarily due to a 20% increase in the average number of employees working
      in
      the exploration and production area. Total depreciation, depletion and
      amortization (“DD&A”) increased $5.7 million or 23%. Higher production
      volumes accounted for 22% of the increase while increases in our DD&A rate
      represented 78% of the increase. The increase in our DD&A rate in the second
      quarter of 2007 compared to the second quarter of 2006 resulted primarily from
      an 18% increase in our finding cost in 2006 and continued increases in our
      finding cost into the first six months of 2007.  Increasing demand for
      drilling rigs prior to the fourth quarter of 2006 throughout our areas of
      exploration increased the dayrates we pay to drill wells in our developmental
      program. Increases in natural gas and oil prices over the last two years have
      also caused increased sales prices for producing property acquisitions and
      even
      with the increased sales prices, we continue to see strong competition for
      producing property acquisitions.
 
 31
 Our
      mid-stream segment is engaged primarily in the mid-stream buying and
      selling, gathering, processing and treating of natural gas. We operate four
      natural gas treatment plants and own seven operating processing plants, 37
      active gathering systems and 641 miles of pipeline. These operations are
      conducted in Oklahoma, Texas, Louisiana and Kansas. Intercompany revenue from
      services and purchases of production between our natural gas gathering and
      processing segment and our oil and natural gas segments has been eliminated.
      Our
      mid-stream revenues were $14.0 million or 65% higher in the second quarter
      of
      2007 as compared to the second quarter of 2006 due to the higher volumes of
      natural gas sales and processing combined with higher natural gas and liquids
      prices. The average price for gas sold was 18% higher and the average price
      for
      liquids sold was 9% higher. Gas processing volumes per day increased 38% between
      the comparative quarters and gas liquids sold per day increased 127% between
      the
      comparative quarters.  A 10% decrease in gathering volumes per day and
      a 13% decrease in the average price received for gas transportation volumes
      combined to partially offset the increase in revenue from natural gas sales
      and
      processing. The significant increase in volumes processed per day is primarily
      attributable to the acquisition of a processing plant in September of 2006
      and
      to a lesser extent volumes from wells added to existing systems throughout
      2006.
      Gas liquids sold volumes per day increased due to recent upgrades to several
      of
      our processing facilities. Operating costs increased 68% in the second quarter
      of 2007 compared with the second quarter of 2006 due to a 19% increase in
      prices paid for natural gas purchased, a 35% increase in natural gas volumes
      purchased, a 69% increase in field direct operating cost due to the growth
      in
      our natural gas gathering systems and the volume of natural gas processed and
      a
      49% increase in general and administrative expenses. The total number of
      employees working in our mid-stream segment increased by 38%. The 107% increase
      in depreciation and amortization in our mid-stream segment came from the
      additional depreciation and amortization associated with tangible and intangible
      assets acquired between the comparative periods.  Gas gathering
      volumes per day in the second quarter of 2007 were down 3% compared to the
      first
      quarter of 2007 primarily due to a slow down of new well connections associated
      with adverse winter weather and pipeline construction delays. Subsequent
      declines will continue until further field development results in new well
      connections. Gas processing volumes per day in the second quarter of 2007 were
      relatively unchanged compared to the first quarter of 2007.
  General
      and administrative expense increased $0.8 million in the second quarter of
      2007
      compared to the second quarter of 2006.  The increase in cost was
      primarily from a 17% increase in the number of employees associated with the
      growth of the company and the increases in employee compensation
      cost.
 
 Total
      interest expense increased 70% between the comparative quarters. Average debt
      outstanding was 52% higher in the second quarter of 2007 as compared to the
      second quarter of 2006 primarily due to the acquisition of producing properties
      in the last four months of 2006 and the acquisition of a drilling company in
      the
      second quarter of 2007.  Average debt outstanding accounted for
      approximately 84% of the interest expense increase, with the remaining 16%
      resulting from an increase in average interest rates on our bank debt. Interest
      expense was reduced $0.2 million from the settlements of our interest rate
      swap.
      Associated with our increased level of development of oil and natural gas
      properties, the construction of additional drilling rigs and the construction
      of
      gas gathering systems, we capitalized $1.2 million of interest in the second
      quarter of 2007 compared with $0.9 million in the second quarter of
      2006.
 
 Income
      tax expense decreased $7.6 million or 17% due primarily to the decrease in
      income before income taxes. Our effective tax rate for the second quarter of
      2007 was 35.8% versus 37.1% in the second quarter of 2006 due primarily to
      the
      increase in manufacturing tax deduction for 2007. The portion of our taxes
      reflected as current income tax expense for the second quarter of 2007 was
      $19.7
      million or 54% of total income tax expense as compared with $33.1 million or
      75%
      of total income tax expense in the second quarter of 2006.  Income
      taxes paid in the second quarter of 2007 were $28.0 million.
 
 
  32
  **Six
      Months Ended June 30, 2007 versus Six Months Ended June 30,
      2006**
 
 Provided
      below is a comparison of selected operating and financial data for the first
      six
      months of 2007 versus the first six months of 2006:
 
 **Six
                Months Ended**
            
            **Six
                Months Ended****June
                30,**
            
            **June
                30,**
            
            **Percent****2007**
            
            **2006**
            
            **Change**Total
                Revenue
            
            
            
            $
            563,911,000
            
            $
            563,157,000
            
            ---
            %Net
                Income
            
            
            
            $
            130,048,000
            
            $
            149,730,000
            
            (13
            )%**Drilling:**Revenue
            
            
            
            $
            314,634,000
            
            $
            337,338,000
            
            (7
            )%Operating
                costs excluding depreciation
            
            
            
            $
            151,016,000
            
            $
            159,426,000
            
            (5
            )%Percentage
                of revenue fromdaywork
                contracts
            
            
            
            
            100
            %
            
            100
            %
            ---Average
                number of rigs in use
            
            
            
            
            97.4
            
            
            109.5
            
            (11
            )%Average
                dayrate on dayworkcontracts
            
            
            
            $
            19,062
            
            $
            17,870
            
            7
            %Depreciation
            
            
            
            $
            26,399,000
            
            $
            24,686,000
            
            7
            %**Oil
                and Natural Gas:**Revenue
            
            
            
            $
            182,449,000
            
            $
            176,280,000
            
            3
            %Operating
                costs excluding depreciation,depletion
                and amortization
            
            
            
            $
            46,600,000
            
            $
            37,294,000
            
            25
            %Average
                natural gas price (Mcf)
            
            
            
            $
            6.58
            
            $
            6.41
            
            3
            %Average
                oil price (Bbl)
            
            
            
            $
            50.66
            
            $
            55.88
            
            (9
            )%Natural
                gas production (Mcf)
            
            
            
            
            21,301,000
            
            
            21,150,000
            
            1
            %Oil
                production (Bbl)
            
            
            
            
            789,000
            
            
            685,000
            
            15
            %Depreciation,
                depletion andamortization
                rate (Mcfe)
            
            
            
            $
            2.29
            
            $
            1.94
            
            18
            %Depreciation,
                depletion andamortization
            
            
            
            $
            60,070,000
            
            $
            49,223,000
            
            22
            %**Gas
                Gathering and Processing:**Revenue
            
            
            
            $
            66,537,000
            
            $
            47,202,000
            
            41
            %Operating
                costs excluding depreciation,and
                amortization
            
            
            
            $
            58,896,000
            
            $
            41,518,000
            
            42
            %Depreciation
                and amortization
            
            
            
            $
            4,894,000
            
            $
            2,382,000
            
            105
            %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
            %General
                and Administrative Expense
            
            
            
            $
            10,429,000
            
            $
            8,368,000
            
            25
            %Interest
                Expense
            
            
            
            $
            3,370,000
            
            $
            2,007,000
            
            68
            %Income
                Tax Expense
            
            
            
            $
            72,189,000
            
            $
            88,523,000
            
            (18
            )%Average
                Interest Rate
            
            
            
            
            6.14
            %
            
            5.60
            %
            10
            %Average
                Long-Term Debt Outstanding
            
            
            
            $
            171,862,000
            
            $
            115,922,000
            
            48
            %
 
 Industry
      demand for our drilling rigs remained strong throughout the first nine months
      of
      2006 before declining in the fourth quarter of 2006 and into the first six
      months of 2007. The reduction in demand for drilling rigs was primarily the
      result of the evaluation of the economics of drilling prospects by the operators
      using our contract drilling services after natural gas prices declined
      significantly in the last half of the third quarter of 2006 combined with the
      high levels of natural gas storage throughout the majority of the winter season
      and again this summer.
  33
 
 Drilling
        revenues decreased $22.7 million or 7% in the first six months of 2007 versus
        the first six months of 2006. Since the first quarter of 2006, we have placed
        16
        additional drilling rigs into service. We have constructed seven drilling
        rigs
        and in June 2007 we acquired nine drilling rigs. Thirteen of these additional
        drilling rigs provided contract drilling services in the first six months
        of
        2007 increasing drilling revenues by $16.7 million or 5% of revenues in the
        first six months of 2006. Revenues for rigs previously owned declined $39.4
        million or 12% from revenues in the first six months of 2006 and more than
        offset the increase in revenue from rigs added subsequent to the first quarter
        of 2006. Average rig utilization declined from 109.5 rigs in the first six
        months of 2006 to 97.4 in the first six months of 2007. The decline in rig
        utilization decreased drilling revenues by $37.3 million while increases
        in
        dayrates between the comparative six months periods provided additional revenue
        of $14.6 million partially offsetting utilization decreases. Our average
        dayrate
        in the first six months of 2007 was 7% higher than in the first six months
        of 2006.  Demand for our drilling rigs is anticipated to remain in the
        80% to 85% range in the short term. With decreases in drilling rig demand,
        we
        experienced a 4% decline in the second quarter 2007 average dayrate compared
        to
        the first quarter 2007 average dayrate and we expect further decreases in
        average dayrates to continue into the third quarter.
 
 Drilling
      operating costs decreased $8.4 million or 5% between the comparative six month
      periods. Operating cost decreased as utilization dropped 12.1 rigs between
      the
      comparative six month periods. Operating cost per day increased $523 in the
      first six months of 2007 when compared with the first six months of
      2006 and partially offset the decrease from less operating days. The
      majority of the increase in cost per day was attributable to indirect drilling
      cost for repair supplies and maintenance and property taxes and costs directly
      associated with drilling wells. With continued competition for qualified labor
      and utilization continuing at 80% or above, we expect our drilling rig expenses
      per day to remain steady or increase slightly over the remainder of 2007.
      Contract drilling depreciation increased $1.7 million or 7%. The addition of
      the
      16 drilling rigs placed in service since the first quarter of 2006 and
      additional assets acquired in the 2007 second quarter rig acquisition increased
      depreciation with the increase partially offset from the effect of decreased
      utilization.
 
 Oil
      and
      natural gas revenues increased $6.2 million or 3% in the first six months of
      2007 as compared to the first six months of 2006 due to an increase in
      equivalent production volumes of 3% and an increase in average natural gas
      prices. The increases were partially offset by decreased oil prices. Average
      natural gas prices between the comparative six month periods increased 3% to
      $6.58 per Mcf while oil prices declined 9% to $50.66 per barrel. In the first
      six months of 2007, natural gas production increased by 1% while oil production
      increased 15%. Increased natural gas and oil production came primarily from
      our
      ongoing development drilling activity and from acquisitions completed in
      2006.  Production increases primarily in the first quarter of 2007
      were limited due to the impact from a Texas refinery fire, adverse winter
      weather, pipeline construction delays preventing the connection of wells
      recently drilled and the timing of completion of certain wells. With the
      continuation of our internal drilling program and our previous acquisitions,
      we
      believe our total production for 2007 compared to 2006 will increase 6% to
      10%.
      Actual increases in revenues, however, will also be driven by commodity prices
      received for our production.
 
 Oil
      and
      natural gas operating costs increased $9.3 million or 25% in the first six
      months of 2007 as compared to the first six months of 2006. An increase in
      the
      average cost per equivalent Mcf produced represented 87% of the increase in
      production costs with the remaining 13% of the increase attributable to the
      increase in volumes produced from both development drilling and producing
      property acquisitions. Lease operating expenses represented 74% of the increase,
      gross production taxes 11%, general and administrative cost directly related
      to
      oil and natural gas production 13% and increased accretion on plugging liability
      2%. Lease operating expenses per Mcfe increased 26% between the comparative
      six month periods as post production transportation cost, salt water disposal
      fees and compression increased along with a 63% increase in workover
      cost.  Gross production taxes increased due to the increase in oil and
      natural gas volumes produced between the comparative quarters and the increase
      in natural gas prices. General and administrative expenses increased as labor
      costs increased primarily due to a 13% increase in the average number of
      employees working in the exploration and production area. Total depreciation,
      depletion and amortization (“DD&A”) increased $10.8 million or 22%. Higher
      production volumes accounted for 14% of the increase while increases in our
      DD&A rate represented 86% of the increase. The increase in our DD&A rate
      in the first six months of 2007 compared to the first six months of 2006
      resulted primarily from an 18% increase in our finding cost in 2006 and
      continued increases in our finding cost into the first six months of
      2007.  Increasing demand for drilling rigs prior to the fourth quarter
      of 2006 throughout our areas of exploration increased the dayrates we pay to
      drill wells in our developmental program. Increases in natural gas and oil
      prices over the last two years have also caused increased sales prices for
      producing property acquisitions and even with the increased sales prices, we
      continue to see strong competition for producing property
      acquisitions.
 
 34
 
 Our
      mid-stream segment is engaged primarily in the mid-stream buying and
      selling, gathering, processing and treating of natural gas. We operate four
      natural gas treatment plants and own seven operating processing plants, 36
      active gathering systems and 641 miles of pipeline. These operations are
      conducted in Oklahoma, Texas, Louisiana and Kansas. Intercompany revenue from
      services and purchases of production between our natural gas gathering and
      processing segment and our oil and natural gas segments has been eliminated.
      Our
      mid-stream revenues were $19.3 million or 41% higher in the first six months
      of
      2007 as compared to the first six months of 2006 due to the higher volumes
      of
      natural gas sales and processing combined with higher natural gas prices. The
      average price for gas sold was 1% higher and the average price for liquids
      sold
      was unchanged. Gas processing volumes per day increased 39% between the
      comparative six month periods and gas liquids sold per day increased 107%
      between the comparative six month periods.  A 3% decrease in gathering
      volumes per day as gas transportation prices remained unchanged partially offset
      the increase in revenue from natural gas sales and processing. The significant
      increase in volumes processed per day is primarily attributable to the
      acquisition of a processing plant in September of 2006 and to a lesser extent
      volumes from wells added to existing systems throughout 2006. Gas liquids sold
      volumes per day increased due to recent upgrades to several of our processing
      facilities. Operating costs increased 42% in the first six months of 2007
      compared with the first six months of 2006 due an 19% increase in prices paid
      for natural gas purchased, to a 19% increase in natural gas volumes purchased,
      an 84% increase in field direct operating cost due to the growth in our natural
      gas gathering systems and the volume of natural gas processed and a 40% increase
      in general and administrative expenses. The total number of employees working
      in
      our mid-stream segment increased by 13%. The 105% increase in depreciation
      and
      amortization in our mid-stream segment came from the additional depreciation
      and
      amortization associated with tangible and intangible assets acquired between
      the
      comparative periods.  Gas gathering volumes per day in the second
      quarter of 2007 were down 3% compared to the first quarter of 2007 primarily
      due
      to a slow down of new well connections associated with adverse winter weather
      and pipeline construction delays. Subsequent declines will continue until
      further field development results in new well connections. Gas processing
      volumes per day in the second quarter of 2007 were relatively unchanged compared
      to the first quarter of 2007.
  General
      and administrative expense increased $2.1 million in the first six months of
      2007 compared to the first six months of 2006.  The increase in cost
      was primarily from a 17% increase in the number of employees associated with
      the
      growth of the company and increases in employee compensation cost.
 
 Total
      interest expense increased 68% between the comparative six month periods.
      Average debt outstanding was 48% higher in the first six months of 2007 as
      compared to the six months of 2006 primarily due to the acquisition of producing
      properties in the last four months of 2006 and the acquisition of a drilling
      company in the second quarter of 2007. Average debt outstanding accounted for
      approximately 78% of the interest expense increase, with the remaining 22%
      resulting from an increase in average interest rates on our bank debt. Interest
      expense was reduced $0.3 million from settlements of our interest rate swap.
      Associated with our increased level of development of oil and natural gas
      properties, the construction of additional drilling rigs and the construction
      of
      gas gathering systems, we capitalized $2.2 million of interest in the first
      six
      months of 2007 compared with $1.6 million in the first six months of
      2006.
 
 Income
      tax expense decreased $16.3 million or 18% due primarily to the decrease in
      income before income taxes. Our effective tax rate for the first six months
      of
      2007 was 35.7% versus 37.2% in the first six months of 2006 due primarily to
      the
      increase in manufacturing tax deduction for 2007. The portion of our taxes
      reflected as current income tax expense for the first six months of 2007 was
      $42.3 million or 59% of total income tax expense in the first six months of
      2007
      as compared with $63.3 million or 72% of total income tax expense in the first
      six months of 2006.  Income taxes paid in the first six months of 2007
      were $36.0 million.
 
 In
      January 2006, one of our drilling rigs was destroyed by a fire.  No
      personnel were injured although the drilling rig was a total
      loss.  Insurance proceeds for the loss exceeded our net book value and
      provided a gain of approximately $1.0 million which is recorded in other
      revenues.
 
 **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
   36
 
 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:
  •
            
            the
                amount and nature of our future capital expenditures;•
            
            the
                amount of wells to be drilled or reworked;•
            
            prices
                for oil and natural gas;•
            
            demand
                for oil and natural gas;•
            
            our
                exploration prospects;•
            
            estimates
                of our proved oil and natural gas reserves;•
            
            oil
                and natural gas reserve potential;•
            
            development
                and infill drilling potential;•
            
            our
                drilling prospects;•
            
            expansion
                and other development trends of the oil and natural gas
                industry;•
            
            our
                business strategy;•
            
            production
                of oil and natural gas reserves;•
            
            growth
                potential for our mid-stream operations;•
            
            gathering
                systems and processing plants we plan to construct or
                acquire;•
            
            volumes
                and prices for natural gas gathered and processed;•
            
            expansion
                and growth of our business and operations; and•
            
            demand
                for our drilling rigs and drilling rig
                rates.
  These
      statements are based on certain assumptions and analyses made by us in light
      of
      our experience and our perception of historical trends, current conditions
      and
      expected future developments as well as other factors we believe are appropriate
      in the circumstances. However, whether actual results and developments will
      conform to our expectations and predictions is subject to a number of risks
      and
      uncertainties which could cause actual results to differ materially from our
      expectations, including:
  •
            
            the
                risk factors discussed in this report and in the documents we incorporate
                by reference;•
            
            general
                economic, market or business conditions;•
            
            the
                nature or lack of business opportunities that we
                pursue;•
            
            demand
                for our land drilling services;•
            
            changes
                in laws or regulations; and•
            
            other
                factors, most of which are beyond our
                control.
 
 You
      should not place undue reliance on any of these forward-looking statements.
      Except as required by law, we disclaim any current intention to update
      forward-looking information and to release publicly the results of any future
      revisions we may make to forward-looking statements to reflect events or
      circumstances after the date of this report to reflect the occurrence of
      unanticipated events.
 
 A
      more
      thorough discussion of forward-looking statements with the possible impact
      of
      some of these risks and uncertainties is provided in our Annual Report on Form
      10-K filed with the SEC. We encourage you to get and read that
      document.
  36
  
 **Item
      3.  Quantitative and Qualitative Disclosure about Market
      Risk**
 
 Our
      operations are exposed to market risks primarily as a result of changes in
      commodity prices and interest rates.
  ***Commodity
      Price Risk.***  Our major market risk exposure is in the
      price we receive for our oil and natural gas production. These prices are
      primarily driven by the prevailing worldwide price for crude oil and market
      prices applicable to our natural gas production. Historically, the prices we
      received for our oil and natural gas production have fluctuated and we expect
      these prices to continue to fluctuate. The price of oil and natural gas also
      affects both the demand for our drilling rigs and the amount we can charge
      for
      the use of our drilling rigs. Based on our first six months of 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 cash flow. 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.
  In
      an
      effort to try and reduce the impact of price fluctuations, over the past several
      years we have periodically used hedging strategies to hedge the price we will
      receive for a portion of our future oil and natural gas production. A detailed
      explanation of those transactions has been included under hedging in the
      financial condition portion of Management’s Discussion and Analysis of Financial
      Condition and Results of Operations included above.
  In
      an effort to try and reduce the
      impact of price fluctuations received for natural gas liquids, in June 2007
      we
      entered into a series of natural gas liquid sales and natural gas purchase
      swaps
      to effectively lock in the frac spread we receive on approximately 65% of our
      liquids processed and sold. A detailed explanation of those transactions
      has been included under hedging in the financial condition portion of
      Management’s Discussion and Analysis of Financial Condition and Results of
      Operations included above.
 
 ***Interest
      Rate Risk.***  Our interest rate exposure relates to our
      long-term debt, all of which bears interest at variable rates based on the
      BOKF
      National Prime Rate or the LIBOR Rate. At our election, borrowings under our
      revolving credit facility may be fixed at the LIBOR Rate for periods of up
      to
      180 days. In February 2005, we entered into an interest rate swap for $50.0
      million of our outstanding debt to help manage our exposure to any future
      interest rate volatility. A detailed explanation of this transaction has been
      included under hedging in the financial condition portion of Management’s
      Discussion and Analysis of Financial Condition and Results of Operations
      included above. Based on our average outstanding long-term debt subject to
      the
      floating rate in the first six months of 2007, a 1% change in the floating
      rate
      would reduce our annual pre-tax cash flow by approximately $1.2
      million.
 
 **Item
      4.  Controls and Procedures**
 
 ***Evaluation
      of Disclosure Controls and Procedures.*** As of the end of the period
      covered by this report, we carried out an evaluation, under the supervision
      and
      with the participation of our management, including our Chief Executive Officer
      and Chief Financial Officer, of the effectiveness of the design and operation
      of
      our disclosure controls and procedures under Exchange Act Rule 13a-15. Based
      on
      that evaluation, our Chief Executive Officer and Chief Financial Officer
      concluded that the company’s disclosure controls and procedures are effective as
      of June 30, 2007 in ensuring the appropriate information is recorded, processed,
      summarized and reported in our periodic SEC filings relating to the company
      (including its consolidated subsidiaries) and is accumulated and communicated
      to
      the Chief Executive Officer, Chief Financial Officer and management to allow
      timely decisions.
 
 ***Changes
      in Internal Controls.*** There were no changes in the company’s
      internal controls over financial reporting during the quarter ended June 30,
      2007 that could significantly affect these internal controls.
 
 
  37
  
 **PART
      II. OTHER
      INFORMATION**
 
 **Item
      1.  Legal Proceedings**
 
 The
      company is a party to certain litigation arising in the ordinary course of
      its
      business. Although the amount of any liability that could arise with respect
      to
      these actions cannot be accurately predicted, in the company’s opinion, any such
      liability will not have a material adverse effect on our business, financial
      condition and/or operating results.
 
 **Item
      1A.  Risk Factors**
 
 In
      addition to the other information set forth in this report, you should carefully
      consider the factors discussed in Part I, "Item 1A. Risk Factors" in our Annual
      Report on Form 10-K for the year ended December 31, 2006, which could materially
      affect our business, financial condition or future results. The risks described
      in our Annual Report on Form 10-K are not the only risks facing our company.
      Additional risks and uncertainties not currently known to us or that we
      currently deem to be immaterial also may materially adversely affect our
      business, financial condition and/or operating results.
 
 There
      have been no material changes to the risk factors disclosed in Item 1A in our
      Form 10-K for the year ended December 31, 2006.
 
 **Item
      2.  Unregistered Sales of Equity Securities and Use of
      Proceeds**
 
 Not
      applicable
 
 **Item
      3.  Defaults Upon Senior Securities**
 
 Not
      applicable
 
 **Item
      4.  Submission of Matters to a Vote of Security
      Holders**
 
 On
      May 2,
      2007 we held our Annual Meeting of Stockholders. At the meeting the following
      matters were voted on, with each receiving the votes indicated:
 
 I.
            Election
                of Director Nominees William B. Morgan, John H. Williams and Larry
                D.
                Pinkston for a three-year term expiring in
                2010.
 
 **Numbers
                of**
            
            **Against
                or****Nominee**
            
            **Votes
                For**
            
            **Withheld**William
                B. Morgan
            
            40,984,461
            
            1,034,430John
                H. Williams
            
            41,010,193
            
            1,008,698Larry
                D. Pinkston
            
            41,025,845
            
            993,046
 
 The
      following directors, whose term of office did not expire at the annual meeting,
      continue as directors of the Company:  King P. Kirchner, Don Cook, J.
      Michael Adcock, John G. Nikkel, Robert J. Sullivan, Jr., and Gary R.
      Christopher.
 
 II.
            Ratification
                of the appointment of PricewaterhouseCoopers LLP as our independent
                registered public accounting firm for the fiscal year
                2007.
 
 For
                -
            41,910,421Against
                -
            56,528Abstain
                -
            51,947
 
  38
  
 **Item
      5.  Other Information**
 
 Not
      applicable
 
 **Item
      6.  Exhibits**
 
 Exhibits:
 
 15
            Letter
                re:  Unaudited Interim Financial Information.31.1
            Certification
                of Chief Executive Officer under Rule 13a – 14(a) of
                theExchange
                Act.31.2
            Certification
                of Chief Financial Officer under Rule 13a – 14(a) of
                theExchange
                Act.32
            Certification
                of Chief Executive Officer and Chief Financial Officer
                underRule
                13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as
                adoptedunder
                Section 906 of the Sarbanes-Oxley Act of
                2002.
  39
  **SIGNATURES**
 
 
 Pursuant
      to the requirements of the Securities Exchange Act of 1934, the Registrant
      has
      duly caused this report to be signed on its behalf by the undersigned thereunto
      duly authorized.
 
 Unit
                CorporationDate:   August
                2, 2007
            By:  /s/
                Larry D. PinkstonLARRY
                D. PINKSTONChief
                Executive Officer and DirectorDate:   August
                2, 2007
            By:  /s/
                David T. MerrillDAVID
                T. MERRILLChief
                Financial Officer andTreasurer
 
  40