Document:

Form of OceanFirst Financial Corp.

 Exhibit 10.16 
  
 OCEANFIRST FINANCIAL CORP. 
 2000 STOCK OPTION
PLAN 
 NON-STATUTORY OPTION AWARD AGREEMENT 
  

			
	 Name of Recipient:
	  	_________________
	 Number of Shares
	  	 
	 Subject to Options:
	  	_________________
		
	 Grant of Limited Rights:
	  	Yes x  No
		
	 Exercise Price:
	  	_________________
		
	 Term of Options:
	  	10 years, commencing                          (the “Date of
Grant”).
		
	 Payment of Exercise Price:
	  	The exercise price may be paid in cash, borrowed funds (to the extent permitted by law) or with previously acquired Common Stock.
		
	 Effective Date:
	  	_________________
		
	 Vesting Schedule:
	  	20% is earned after each year of continuous service, commencing on              and on each
             thereafter through                 .
		
	 Voting:
	  	The Recipient will having voting rights over the Common Stock actually acquired only upon the exercise of the Non-statutory Stock Options and acquisition of the Common Stock.
		
	 Distribution:
	  	Shares of Common Stock subject to the Non-statutory Stock Options will be distributed as soon as practicable upon exercise.
		
	 Designation of Beneficiary:
	  	A Beneficiary may be designated in writing to receive, in the event of death, any award to which the Recipient would be entitled pursuant to the OceanFirst Financial Corp. 2000 Stock Option
Plan (the “Plan”) under this Non-statutory Option Award Agreement.
		
	 Effect of termination of
 employment because of:
	  	 
		
	 (a) Death or Disability:
	  	Non-statutory Stock Options which have not yet vested, vest upon death or Disability. After termination of employment all Non-statutory Stock Options are exercisable for one year after such
termination of employment, but not after the tenth anniversary of the Date of Grant. Vested Limited Rights may be exercised only upon a Change in Control.

  

			
	 (b) Retirement:
	  	All unexercised Non-statutory Stock Options that are vested as of the date of termination are exercisable for a period of three years following termination, but not after the tenth
anniversary of the Date of Grant. All unvested Non-statutory Stock options are forfeited and the rights to such unvested Non-statutory Options cease upon termination of employment.
		
	 (c) Cause:
	  	All unvested Non-statutory Stock Options and all vested Non-statutory Stock Options not yet exercised expire immediately upon termination of employment.
		
	 (d) Other reasons:
	  	All unexercised Non-statutory Stock Options that are vested as of the date of termination are exercisable for a period of three months following termination, but not after the tenth
anniversary of the Date of Grant. All unvested Non-statutory Stock Options are forfeited and the rights to such unvested Non-statutory Stock Options cease upon termination of employment.
		
	 Non-Transferability:
	  	No Non-statutory Stock Option shall be transferable by the Recipient other than by will or the laws of interstate succession or pursuant to a domestic relations order or unless determined
otherwise by the committee.

  
 This Non-statutory
Option Award Agreement is subject to the terms and conditions of the Plan. Neither the Plan nor this grant create any right on the part of any employee to continue in the employ of OceanFirst Bank, OceanFirst Financial Corp. or any affiliates
thereof. All capitalized terms herein shall have the same meaning as those contained in the Plan. 
  
 The Recipient hereby acknowledges that all decisions, determinations and interpretations of the Board of Directors, or the committee hereof, in respect of
the Plan and this Non-statutory Option Award Agreement shall be final and conclusive. 
  
 IN WITNESS WHEREOF, OceanFirst Financial Corp. has caused this Non-statutory Option Award Agreement to be executed, and said recipient has hereunto set his hand, as of
             day of                 , 2005. 
  

			
	 OCEANFIRST FINANCIAL CORP.

		
	By:	 	 
	
	 RECIPIENTForm of Amended & Restated OceanFirst Financial Corp.

 Exhibit 10.17 
  
 AMENDED AND RESTATED 
 OCEANFIRST
FINANCIAL CORP. 
 1997 INCENTIVE PLAN 
 STOCK AWARD AGREEMENT 
  

			
	 Name of Recipient:
	  	_______________
		
	 Total Stock Award:
	  	_______________
		
	 Installment Schedule:
	  	_______________
	 	  	_______________
		
	 Vesting Schedule:
	  	Installments are earned after each period of continuous employment commencing on
                         and on each
                        , thereafter through
                    .
		
	 Date of Grant:
	  	_______________
		
	 Distribution:
	  	Shares of Common Stock plus any dividends and earnings on such shares, will be distributed as soon as practicable upon vesting.
		
	 Effect of termination of
	  	 
	 Employment because of:
	  	 
		
	 (a) Death or Disability:
	  	All unvested shares subject to this Stock Award vest immediately upon such termination of employment.
		
	 (b) Cause:
	  	All unvested shares subject to this Stock Award shall be forfeited as of the date of termination and any rights the Recipient had to such shares become null and void.
		
	 (c) Other Reasons:
	  	Unless otherwise determined by the Committee, all unvested shares subject to this Stock Award shall be forfeited as of the date of termination and any rights the Recipient had to such shares
become null and void.
		
	 Voting:
	  	A Recipient is entitled to direct the Trustee as to the voting of shares subject to this Stock Award that have been granted, but have not yet been earned and distributed.

  

			
	 Non-Transferability:
	  	The Recipient of this Stock Award shall not sell, transfer, assign, pledge or otherwise encumber shares subject to this Stock Award until full vesting of such shares has
occurred.
		
	 	  	Unless determined otherwise by the Committee and except in the event of the Recipient’s death or pursuant to a domestic relations order, this Stock Award is not transferable and may be
earned only in the Recipient’s lifetime. Upon the death of the Recipient, this Stock Award is transferable by will or the laws of descent and distribution.

  
 In the event the
Recipient is subject to the provisions of Section 16 of the Securities Exchange Act of 1934, as amended, the Committee must give written consent to permit the shares subject to this Stock Award Agreement to be sold or otherwise disposed of within
six (6) months following the Date of Grant of this Stock Award. 
  

			
	 Designation of Beneficiary:
	  	A Beneficiary may be designated in writing to receive in the event of death, any award to which the Recipient would be entitled pursuant to the Plan under the Stock Award
Agreement.

  
 The Stock Award Agreement is subject
to the terms and conditions of the Amended and Restated OceanFirst Financial Corp. 1997 Incentive Plan (the “Plan”). Neither the Plan or this grant create any right on the part of an employee to continue in the service of OceanFirst Bank,
OceanFirst Financial Corp. or any affiliates thereof. All capitalized terms herein shall have the same meaning as those contained in the Plan. 
  
 The Recipient hereby acknowledges that all decisions, determinations and interpretations of the Board of Directors, or the Committee thereof, in respect of the Plan and
this Stock Award Agreement shall be final and conclusive. 
  
 IN WITNESS WHEREOF,
OceanFirst Financial Corp. has caused this Stock Award Agreement to be executed, and said Recipient has hereunto set his hand, as of this          day of
                    , 2005. 
  

			
	 OCEANFIRST FINANCIAL CORP.

		
	By:	 	 
	
	 RECIPIENTUnit 2005 Employee Oil and Gas Limited Partnership Agr. of Limited Partnership

 Exhibit 10.2.44 
 CONFIDENTIAL 
  
 For Private Placement Purposes
Only 
  
 UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP

 7130 South Lewis, Suite 1000 
 Tulsa, Oklahoma 74136 
 (918) 493-7700 
  
 A PRIVATE OFFERING 
 OF

 UNITS OF LIMITED PARTNERSHIP INTEREST 
  

  
 THESE SECURITIES HAVE NOT
BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, OR UNDER APPLICABLE STATE SECURITIES ACTS IN RELIANCE ON EXEMPTIONS PROVIDED BY SUCH ACTS. THESE SECURITIES MAY NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION
UNDER SUCH ACTS OR AN OPINION OF COUNSEL ACCEPTABLE TO THE GENERAL PARTNER THAT SUCH REGISTRATION IS NOT REQUIRED. FURTHER, THE RESALE OF A UNIT MAY RESULT IN SUBSTANTIAL TAX LIABILITY TO THE INVESTOR. SEE “FEDERAL INCOME TAX
CONSIDERATIONS.” ACCORDINGLY, THESE UNITS SHOULD BE CONSIDERED ONLY FOR LONG-TERM INVESTMENT. SEE “PLAN OF DISTRIBUTION — SUITABILITY OF INVESTORS.” 
  

  
 THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IS PROVIDED BY THE GENERAL PARTNER SOLELY FOR THE PERSONS RECEIVING IT FROM THE GENERAL PARTNER AND ANY REPRODUCTION OR DISTRIBUTION OF THIS PRIVATE OFFERING MEMORANDUM, IN
WHOLE OR IN PART, OR THE DIVULGENCE OF ANY OF ITS CONTENTS IS PROHIBITED AND MAY CONSTITUTE A VIOLATION OF CERTAIN STATE SECURITIES LAWS. THE OFFEREE, BY ACCEPTING DELIVERY OF THIS PRIVATE OFFERING MEMORANDUM, AGREES TO RETURN IT AND ALL ENCLOSED
DOCUMENTS TO THE GENERAL PARTNER IF THE OFFEREE DOES NOT UNDERTAKE TO PURCHASE ANY OF THE UNITS OFFERED HEREBY. 
  

  
 Private Offering Memorandum Date December 23, 2004

 600 Preformation 
 Units of Limited Partnership Interest 
 in the 
 UNIT 2005 EMPLOYEE 
 OIL AND GAS
LIMITED PARTNERSHIP 
  

  
 $1,000 Per Unit Plus Possible 
 Additional
Assessments of $100 Per Unit 
 (Minimum Investment - 2 Units) 
 Minimum Aggregate Subscriptions Necessary 
 to Form Partnership - 50 Units 
  

  
 A maximum of 600 (minimum of 50) units of limited partnership interest (“Units”) in the UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP, a
proposed Oklahoma limited partnership (the “Partnership”), are being offered privately only to certain employees of Unit Corporation (“UNIT”) and its subsidiaries and the directors of UNIT at a price of $1,000 per Unit.
Subscriptions shall be for not less than 2 Units ($2,000). The Partnership is being formed for the purpose of conducting oil and gas drilling and development operations. Purchasers of the Units will become Limited Partners in the Partnership. Unit
Petroleum Company (“UPC” or the “General Partner”) will serve as General Partner of the Partnership. UPC’s address is 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136, and telephone (918) 493-7700. 
  
 THE RIGHTS AND OBLIGATIONS OF THE GENERAL PARTNER 
 AND THE LIMITED PARTNERS ARE GOVERNED BY THE 
 AGREEMENT OF LIMITED PARTNERSHIP (THE “AGREEMENT”), 
 A COPY OF WHICH ACCOMPANIES THIS MEMORANDUM AND IS

 INCORPORATED HEREIN BY REFERENCE 
  
 AN INVESTMENT IN THE UNITS IS SPECULATIVE AND INVOLVES 
 A HIGH DEGREE OF RISK. SEE “RISK FACTORS.” CERTAIN 
 SIGNIFICANT RISKS INCLUDE:

  

	 	•	 	Drilling to establish productive oil and natural gas properties is inherently speculative. 

  

	 	•	 	Participants will rely solely on the management capability and expertise of the General Partner. 

  

	 	•	 	Limited Partners must assume the risks of an illiquid investment. 

  

	 	•	 	Investment in the Units is suitable only for investors having sufficient financial resources and who desire a long-term investment. 

  

	 	•	 	Conflicts of interest exist and additional conflicts of interest may arise between the General Partner and the Limited Partners, and there are no pre-determined procedures for
resolving any such conflicts. 

  

	 	•	 	Significant tax considerations to be considered by an investor include: 

  

	 	•	 	possible audit of income tax returns of the Partnership and/or the Limited Partners and adjustment to their reported tax liabilities; and 

  

	 	•	 	a Limited Partner will not benefit from his or her share of Partnership deductions in excess of his or her share of Partnership income unless he or she has passive income from
other activities. 

  

 ii 

	 	•	 	There can be no assurance that the Partnership will have adequate funds to provide cash distributions to the Limited Partners. The amount and timing of any such distributions
will be within the complete discretion of the General Partner. 

  

	 	•	 	The amount of any cash distribution which a Limited Partner may receive from the Partnership could be insufficient to pay the tax liability incurred by such Limited Partner with
respect to income or gain allocated to such Limited Partner by the Partnership. 

  

	 	•	 	Certain provisions in the Agreement modify what would otherwise be the applicable Oklahoma law as to the fiduciary standards for general partners in limited partnerships. Those
standards in the Agreement could be less advantageous to the Limited Partners than the corresponding fiduciary standards otherwise applicable under Oklahoma law. The purchase of Units may be deemed as consent to the fiduciary standards set forth in
the Agreement. 

  

  

EXCEPT AS STATED UNDER “ADDITIONAL INFORMATION,” NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS
OTHER THAN THOSE CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IN CONNECTION WITH THIS OFFERING AND SUCH REPRESENTATIONS, IF ANY, MAY NOT BE RELIED UPON. THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IS AS OF THE DATE OF THIS
MEMORANDUM UNLESS ANOTHER DATE IS SPECIFIED. 
  

  
 PROSPECTIVE INVESTORS ARE NOT TO CONSTRUE THE CONTENTS OF THIS PRIVATE OFFERING MEMORANDUM AS LEGAL, BUSINESS, OR TAX
ADVICE. EACH INVESTOR SHOULD CONSULT HIS OR HER OWN ATTORNEY, BUSINESS ADVISOR AND TAX ADVISOR AS TO LEGAL, BUSINESS, TAX AND RELATED MATTERS CONCERNING HIS OR HER INVESTMENT. PROSPECTIVE INVESTORS ARE URGED TO REQUEST ANY ADDITIONAL INFORMATION
THEY MAY CONSIDER NECESSARY TO MAKE AN INFORMED INVESTMENT DECISION. 
  

  
 THE SECURITIES OFFERED BY THIS MEMORANDUM HAVE NOT BEEN APPROVED OR
DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION, THE OKLAHOMA SECURITIES COMMISSION OR BY THE SECURITIES REGULATORY AUTHORITY OF ANY OTHER STATE, NOR HAS ANY COMMISSION OR AUTHORITY PASSED UPON OR ENDORSED THE MERITS OF THIS
OFFERING OR THE ACCURACY OR ADEQUACY OF THIS PRIVATE OFFERING MEMORANDUM. ANY REPRESENTATION CONTRARY TO THE FOREGOING IS UNLAWFUL. 
  

  
 THESE UNITS ARE BEING OFFERED SUBJECT TO PRIOR
SALE, TO WITHDRAWAL, CANCELLATION OR MODIFICATION OF THE OFFER WITHOUT NOTICE AND TO THE FURTHER CONDITIONS SET FORTH HEREIN. 
  

 iii 

 ADDITIONAL INFORMATION 
  
 Each prospective investor, or his or her qualified representative named in writing, has the opportunity (1) to obtain
additional information necessary to verify the accuracy of the information supplied herewith or hereafter, and (2) to ask questions and receive answers concerning the terms and conditions of the offering. If you desire to avail yourself of the
opportunity, please contact: 
  
 Mark E. Schell, Esq. 

7130 South Lewis, Suite 1000 
 Tulsa,
Oklahoma 74136 
 (918) 493-7700 
  
 The following documents and instruments are available to qualified offerees upon written request: 
  

	1.	Amended and Restated Certificate of Incorporation and By-Laws of UNIT. 

  

	2.	Certificate of Incorporation and By-Laws of Unit Petroleum Company. 

  

	3.	UNIT’s Employees’ Thrift Plan. 

  

	4.	Restated Unit Corporation Amended and Restated Stock Option Plan and related prospectuses covering shares of Common Stock issuable upon exercise of outstanding options.

  

	5.	UNIT’s 2002 Non-Employee Directors’ Stock Option Plan. 

  

	6.	The Credit Agreement and the notes payable of UNIT. 

  

	7.	All periodic reports on Forms 10-K, 10-Q and 8-K and all proxy materials filed by or on behalf of UNIT with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934, as amended, during calendar year 2004, the annual report to shareholders and all quarterly reports to shareholders submitted by UNIT to its shareholders during calendar year 2004. 

  

	8.	The Registration Statement on Form S-3 (File No. 333-104165) and all supplemental prospectuses filed with the SEC pursuant to Rule 424. 

  

	9.	The agreements of limited partnership for the prior oil and gas drilling programs and prior employee programs of Unit Petroleum Company, UNIT and Unit Drilling and Exploration
Company (“UDEC”). 

  

	10.	All periodic reports filed with the Securities and Exchange Commission and all reports and information provided to limited partners in all limited partnerships of which Unit
Petroleum Company, UNIT or UDEC now serves or has served in the past as a general partner. 

  

	11.	The agreement of limited partnership for the Unit 1986 Energy Income Limited Partnership. 

  

 iv 

 SUMMARY OF CONTENTS 
  

			
	 	  	Page

	 SUMMARY OF PROGRAM
	  	1
	 Terms of the Offering
	  	1
	 Risk Factors
	  	2
	 Additional Financing
	  	3
	 Proposed Activities
	  	4
	 Application of Proceeds
	  	4
	 Participation in Costs and Revenues
	  	5
	 Compensation
	  	5
	 Federal Income Tax Considerations; Opinion of Counsel
	  	5
	 RISK FACTORS
	  	6
	 INVESTMENT RISKS
	  	6
	 TAX STATUS AND TAX RISKS
	  	11
	 OPERATIONAL RISKS
	  	12
	 TERMS OF THE OFFERING
	  	14
	 General
	  	14
	 Limited Partnership Interests
	  	14
	 Subscription Rights
	  	14
	 Payment for Units; Delinquent Installment
	  	15
	 Right of Presentment
	  	16
	 Rollup or Consolidation of Partnership
	  	17
	 ADDITIONAL FINANCING
	  	17
	 Additional Assessments
	  	18
	 Prior Programs
	  	18
	 Partnership Borrowings
	  	18
	 PLAN OF DISTRIBUTION
	  	19
	 Suitability of Investors
	  	19
	 RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER AND AFFILIATES
	  	20
	 PROPOSED ACTIVITIES
	  	20
	 General
	  	20
	 Partnership Objectives
	  	22
	 Areas of Interest
	  	22
	 Transfer of Properties
	  	23
	 Record Title to Partnership Properties
	  	23
	 Marketing of Reserves
	  	23
	 Conduct of Operations
	  	23
	 APPLICATION OF PROCEEDS
	  	24
	 PARTICIPATION IN COSTS AND REVENUES
	  	24
	 COMPENSATION
	  	26
	 Supervision of Operations
	  	26
	 Purchase of Equipment and Provision of Services
	  	27
	 Prior Programs
	  	27
	 MANAGEMENT
	  	29
	 The General Partner
	  	29
	 Officers, Directors and Key Employees
	  	29
	 Prior Employee Programs
	  	32
	 Ownership of Common Stock
	  	33
	 Interest of Management in Certain Transactions
	  	34
	 CONFLICTS OF INTEREST
	  	34
	 Acquisition of Properties and Drilling Operations
	  	34
	 Participation in UNIT’s Drilling or Income Programs
	  	36
	 Transfer of Properties
	  	36
	 Partnership Assets
	  	36
	 Transactions with the General Partner or Affiliates
	  	37
	 Right of Presentment Price Determination
	  	37
	 Receipt of Compensation Regardless of Profitability
	  	37
	 Legal Counsel
	  	37
	 FIDUCIARY RESPONSIBILITY
	  	38
	 General
	  	38
	 Liability and Indemnification
	  	38

  

 v 

			
	 PRIOR ACTIVITIES
	  	39
	 Prior Employee Programs
	  	41
	 Results of the Prior Oil and Gas Programs
	  	42
	 federal income tax considerations
	  	50
	 Summary of Conclusions
	  	51
	 General Tax Effects of Partnership Structure
	  	52
	 Ownership of Partnership Properties
	  	53
	 Intangible Drilling and Development Costs Deductions
	  	54
	 Depletion Deductions
	  	54
	 Depreciation Deductions
	  	55
	 Transaction Fees
	  	55
	 Basis and At Risk Limitations
	  	56
	 Passive Loss Limitations
	  	56
	 Gain or Loss on Sale of Property or Units
	  	57
	 Partnership Distributions
	  	57
	 Partnership Allocations
	  	57
	 Administrative Matters
	  	57
	 Accounting Methods and Periods
	  	58
	 State and Local Taxes
	  	59
	 Individual Tax Advice Should Be Sought
	  	59
	 COMPETITION, MARKETS AND REGULATION
	  	59
	 Marketing of Production
	  	59
	 Regulation of Partnership Operations
	  	60
	 Natural Gas Price Regulation
	  	60
	 Oil Price Regulation
	  	63
	 State Regulation of Oil and Gas Production
	  	63
	 Legislative and Regulatory Production and Pricing Proposals
	  	63
	 Production and Environmental Regulation
	  	64
	 SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
	  	65
	 Partnership Distributions
	  	65
	 Deposit and Use of Funds
	  	65
	 Power and Authority
	  	65
	 Rollup or Consolidation of the Partnership
	  	66
	 Limited Liability
	  	66
	 Records, Reports and Returns
	  	67
	 Transferability of Interests
	  	67
	 Amendments
	  	68
	 Voting Rights
	  	69
	 Exculpation and Indemnification of the General Partner
	  	69
	 Termination
	  	69
	 Insurance
	  	70
	 COUNSEL
	  	70
	 GLOSSARY
	  	70
	 FINANCIAL STATEMENTS
	  	73

  

	
	EXHIBIT A    - AGREEMENT OF LIMITED PARTNERSHIP
	EXHIBIT B     - LEGAL OPINION

  

 vi 

 SUMMARY OF PROGRAM 
  
 This summary is not a complete description of the terms and consequences of an investment in the Partnership and is
qualified in its entirety by the more detailed information appearing throughout this Private Offering Memorandum (this “Memorandum”). For definitions of certain terms used in this Memorandum, see “GLOSSARY.” 
  
 Terms of the Offering 
  
 Limited Partnership Interests. Unit 2005 Employee Oil and Gas
Limited Partnership, a proposed Oklahoma limited partnership (the “Partnership”), offers 600 preformation units of limited partnership interest (“Units”) in the Partnership. The offer is made only to certain
employees of Unit Corporation (“UNIT”) and its subsidiaries and directors of UNIT (see “TERMS OF THE OFFERING — Subscription Rights”). Unless the context otherwise requires, all references in this Memorandum to UNIT
shall include all or any of its subsidiaries. Unit Petroleum Company (“UPC” or the “General Partner”), a wholly owned subsidiary of UNIT, will serve as General Partner of the Partnership. 
  
 To invest in the Units, the Limited Partner Subscription Agreement and
Suitability Statement (the “Subscription Agreement”) (see Attachment I to Exhibit A hereto) must be executed and forwarded to the offices of the General Partner at its address listed on the cover of this Memorandum. The Subscription
Agreement must be received by the General Partner not later than 5:00 P.M. Central Standard Time on January 21, 2005 (extendable by the General Partner for up to 30 days). Subscription Agreements may be delivered to the office of the General
Partner. No payment is required upon delivery of the Subscription Agreement. Payment for the Units will be made either (i) in four equal Installments, the first of such Installments being due on March 15, 2005 and the remaining three of such
Installments being due on June 15, September 15, and December 15, 2005, respectively, or (ii) through equal deductions from 2005 salary commencing immediately after formation of the Partnership. 
  
 The purchase price of each Unit is $1,000, and the minimum permissible
purchase is two Units ($2,000) for each subscriber. Additional Assessments of up to $100 per Unit may be required (see “ADDITIONAL FINANCING — Additional Assessments”). Maximum purchases by employees (other than directors) will be for
an amount equal to one-half of their base salaries for calendar year 2005. Each member of the Board of Directors of UNIT may subscribe for up to 250 Units ($250,000). The Partnership must sell at least 50 Units ($50,000) before the Partnership will
be formed. No Units will be offered for sale after the Effective Date (see “GLOSSARY”) except upon compliance with the provisions of Article XIII of the Agreement. The General Partner may, at its option, purchase Units as a Limited
Partner, including any amount that may be necessary to meet the minimum number of Units required for formation of the Partnership. The Partnership will terminate on December 31, 2035, unless it is terminated earlier pursuant to the provisions of the
Agreement or by operation of law. See “TERMS OF THE OFFERING — Limited Partnership Interests”; “TERMS OF THE OFFERING — Subscription Rights”; and “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT —
Termination.” 
  
 Units will be offered only to those
qualified employees of UNIT or any of its subsidiaries at the date of formation of the Partnership whose annual base salaries for 2004 have been set at $36,000 or more and directors of UNIT who meet certain financial requirements which will enable
them to bear the economic risks of an investment in the Partnership and who can demonstrate that they have sufficient investment experience and expertise to evaluate the risks and merits of such an investment. The offering will be made privately by
the officers and directors of UPC or UNIT, except that in states which require participation by a registered broker-dealer in the offer and sale of securities, the Units will be offered through such broker-dealer as may be selected by the General
Partner. Any participating broker-dealer may be reimbursed for actual out-of-pocket expenses. Such reimbursements will be borne by the General Partner. 
  
 Subscription Rights. Only salaried employees of UNIT or any of its subsidiaries whose annual base salaries for 2004 have been set at $36,000
or more and directors of UNIT are eligible to subscribe for Units. Employees may not purchase Units for an amount in excess of one-half of their base salaries for calendar year 2004. Directors’ subscriptions may not be for more than 250 Units
($250,000). Only employees and directors who are U.S. citizens are eligible to participate in the offering. In addition, employees and directors must be able 

  

 1 

 
to bear the economic risks of an investment in the Partnership and must have sufficient investment experience and expertise to evaluate the risks and merits
of such an investment. See “TERMS OF THE OFFERING — Subscription Rights.” 
  
 Right of Presentment. After December 31, 2006, the Limited Partners will have the right to present their Units to the General Partner for purchase. The General Partner will not be obligated to purchase
more than 20% of the then outstanding Units in any one calendar year. The purchase price to be paid for the Units will be determined by a specific valuation formula. See “TERMS OF THE OFFERING — Right of Presentment” for a description
of the valuation formula and a discussion of the manner in which the right of presentment may be exercised by the Limited Partners. 
  
 Risk Factors 
  
 An investment in the Partnership has many risks. The “RISK FACTORS” section of this Memorandum contains a detailed discussion of the most
important risks, organized into Investment Risks (the risks related to the Partnership’s investment in oil and gas properties and drilling activities, to an investment in the Partnership and to the provisions of the Agreement); Tax Risks (the
risks arising from the tax laws as they apply to the Partnership and its investment in oil and gas properties and drilling activities); and Operational Risks (the risks involved in conducting oil and gas operations). The following are certain of the
risks which are more fully described under “RISK FACTORS”. Each prospective investor should review the “RISK FACTORS” section carefully before deciding to subscribe for Units. 
  
 Investment Risks: 
  

	 	•	 	Future oil and natural gas prices are unpredictable. If oil and natural gas prices go down, the Partnership’s distributions, if any, to the Limited Partners will be adversely
affected. 

  

	 	•	 	The General Partner is authorized under the Agreement to cause, in its sole discretion, the sale or transfer of the Partnership’s assets to, or the merger or consolidation of
the Partnership with, another partnership, corporation or other business entity. Such action could have a material impact on the nature of the investment of all Limited Partners. 

  

	 	•	 	Except for certain transfers to the General Partner and other restricted transfers, the Agreement prohibits a Limited Partner from transferring Units. Thus, except for the limited
right of the Limited Partners after December 31, 2006 to present their Units to the General Partner for purchase, Limited Partners will not be able to liquidate their investments. 

  

	 	•	 	The Partnership could be formed with as little as $50,000 in Capital Contributions (excluding the Capital Contributions of the General Partner). As the total amount of Capital
Contributions to the Partnership will determine the number and diversification of Partnership Properties, the ability of the Partnership to pursue its investment objectives may be restricted in the event that the Partnership receives only the
minimum amount of Capital Contributions. 

  

	 	•	 	The drilling and completion operations to be undertaken by the Partnership for the development of oil and natural gas reserves involve the possibility of a total loss of an
investment in the Partnership. 

  

	 	•	 	The General Partner will have the exclusive management and control of all aspects of the business of the Partnership. The Limited Partners will have no opportunity to participate in
the management and control of any aspect of the Partnership’s activities. Accordingly, the Limited Partners will be entirely dependent upon the management skills and expertise of the General Partner. 

  

	 	•	 	Conflicts of interest exist and additional conflicts of interest may arise between the General Partner and the Limited Partners, and there are no pre-determined procedures for
resolving any such conflicts. Accordingly the General Partner could cause the Partnership to take actions to the benefit of the General Partner but not to the benefit of the Limited Partners. 

  

 2 

	 	•	 	Certain provisions in the Agreement modify what would otherwise be the applicable Oklahoma law as to the fiduciary standards for a general partner in a limited partnership. The
fiduciary standards in the Agreement could be less advantageous to the Limited Partners and more advantageous to the General Partner than corresponding fiduciary standards otherwise applicable under Oklahoma law. The purchase of Units may be deemed
as consent to the fiduciary standards set forth in the Agreement. 

  

	 	•	 	There can be no assurances that the Partnership will have adequate funds to provide cash distributions to the Limited Partners. The amount and timing of any such distributions will
be within the complete discretion of the General Partner. 

  

	 	•	 	The amount of any cash distributions which Limited Partners may receive from the Partnership could be insufficient to pay the tax liability incurred by such Limited Partners with
respect to income or gain allocated to such Limited Partners by the Partnership. 

  
 Tax Risks: 
  

	 	•	 	Tax laws and regulations applicable to partnership investments may change at any time and these changes may be applicable retroactively. 

  

	 	•	 	Certain allocations of income, gain, loss and deduction of the Partnership among the Partners may be challenged by the Internal Revenue Service (the “Service”). A
successful challenge would likely result in a Limited Partner having to report additional taxable income or being denied a deduction. 

  

	 	•	 	Investment as a Limited Partner may be less advisable for a person who does not have substantial current taxable income from trade or business activities in which the Limited
Partner does not materially participate. 

  

	 	•	 	Federal income tax payable by a Limited Partner by reason of his or her allocated share of Partnership income for any year may exceed the Partnership distributions to a Limited
Partner for the year. 

  
 Operational Risks:

  

	 	•	 	The search for oil and gas is highly speculative and the drilling activities conducted by the Partnership may result in a well that may be dry or productive wells that do not
produce sufficient oil and gas to produce a profit or result in a return of the Limited Partners’ investment. 

  

	 	•	 	Certain hazards may be encountered in drilling wells which could lead to substantial liabilities to third parties or governmental entities. In addition, governmental regulations or
new laws relating to environmental matters could increase Partnership costs, delay or prevent drilling a well, require the Partnership to cease operations in certain areas or expose the Partnership to significant liabilities for violations of such
laws and regulations. 

  
 Additional Financing

  
 Additional Assessments. After the
Aggregate Subscription received from the Limited Partners has been fully expended or committed and the General Partner’s Minimum Capital Contribution has been fully expended, the General Partner may make one or more calls for Additional
Assessments from the Limited Partners if additional funds are required to pay the Limited Partners’ share of Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs. The maximum amount of total Additional
Assessments which may be called for by the General Partner is $100 per Unit. See “ADDITIONAL FINANCING — Additional Assessments.” 
  
 Partnership Borrowings. After the General Partner’s Minimum Capital Contribution has been expended, the General Partner may cause the
Partnership to borrow funds required to pay Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties. Additionally, the General Partner may, but is not required to, advance funds to the
Partnership to pay such costs. See “ADDITIONAL FINANCING — Partnership Borrowings.” 
  

 3 

 Proposed Activities 
  
 General. The Partnership is being formed for the purposes of acquiring producing oil and gas properties and
conducting oil and gas drilling and development operations. The Partnership will, with certain limited exceptions, participate on a proportionate basis with UPC in each producing oil and gas lease acquired and in each oil and gas well commenced by
UPC for its own account or by UNIT during the period from January 1, 2005, if the Partnership is formed prior to such date or from the date of the formation of the Partnership if subsequent to January 1, 2005, until December 31, 2005, and will, with
certain limited exceptions, serve as a co-general partner with UNIT in any drilling or income programs which may be formed by the General Partner or UNIT in 2005. See “PROPOSED ACTIVITIES.” 
  
 Partnership Objectives. The Partnership is being formed to
provide eligible employees and directors the opportunity to participate in the oil and gas exploration and producing property acquisition activities of UNIT during 2005. UNIT hopes that participation in the Partnership will provide the participants
with greater proprietary interests in UNIT’s operations and the potential for realizing a more direct benefit in the event these operations prove to be profitable. The Partnership has been structured to achieve the objective of providing the
Limited Partners with essentially the same economic returns that UNIT realizes from the wells drilled or acquired during 2005. 
  
 Application of Proceeds 
  
 The offering proceeds will be used to pay the Leasehold Acquisition Costs incurred by the Partnership to acquire those producing oil and gas leases in
which the Partnership participates and the Leasehold Acquisition Costs, exploration, drilling and development costs incurred by the Partnership pursuant to drilling activities in which the Partnership participates. The General Partner estimates
(based on historical operating experience) that such costs may be expended as shown below based on the assumption of a maximum number of subscriptions in the first column and a minimum number of subscriptions in the second column: 
  

							
	 	  	$600,000
Program

	  	$50,000
Program

	 Leasehold Acquisition Costs of Properties to Be Drilled
	  	$	30,000	  	$	2,500
	 Drilling Costs of Exploratory Wells(1)
	  	 	30,000	  	 	2,500
	 Drilling Costs of Development Wells(1)
	  	 	420,000	  	 	35,000
	 Leasehold Acquisition Costs of Productive Properties
	  	 	120,000	  	 	10,000
	 Reimbursement of General Partner’s Overhead Costs(2)
	  	 	—  	  	 	—  
	 	  	
	
	  	
	

	 Total
	  	$	600,000	  	$	50,000

	(1)	See “GLOSSARY.” 

	(2)	The Agreement provides that the General Partner shall be reimbursed by the Partnership for that portion of its general and administrative overhead expense attributable to its
conduct of Partnership business and affairs but such reimbursement will be made only out of Partnership Revenue. See “COMPENSATION.” 

  

 4 

 Participation in Costs and Revenues 
  
 Partnership costs, expenses and revenues will be allocated among the Partners in the following percentages: 
  

					
	 	  	General Partner

	 	Limited Partners

	 COSTS AND EXPENSES
	  	 	 	 
			
	 Organizational and offering costs of the Partnership and any drilling or income programs in which the Partnership participates as a co-general
partner
	  	100%	 	0%
			
	 All other Partnership costs and expenses
	  	 	 	 
			
	 Prior to time Limited Partner Capital Contributions are entirely expended
	  	1%	 	99%
			
	 After expenditure of Limited Partner Capital Contributions and until expenditure of General Partner’s Minimum Capital
Contribution
	  	100%	 	0%
			
	 After expenditure of General Partner’s Minimum Capital Contribution
	  	General Partner’s
Percentage(1)	 	Limited Partners’
Percentage(1)
			
	 REVENUES
	  	General Partner’s
Percentage(1)	 	Limited Partners’
Percentage(1)

	(1)	See “GLOSSARY.” 

  
 Compensation 
  
 The General Partner will not receive any management fees in connection with the operation of the Partnership. The Partnership will reimburse the General Partner for that portion of its general and administrative overhead expense
attributable to its conduct of Partnership business and affairs. See “COMPENSATION.” 
  
 Federal Income Tax Considerations; Opinion of Counsel 
  
 The General Partner has received an opinion from its tax counsel, Conner & Winters, P.C. (“Conner & Winters”), concerning all material
federal income tax issues applicable to an investment in the Partnership. To be fully understood, the complete discussion of these matters set forth in the full tax opinion in Exhibit B should be read by each prospective investor. Based upon current
laws, regulations, interpretations, and court decisions, Conner & Winters has rendered its opinion that (i) the material federal income tax benefits in the aggregate from an investment in the Partnership will be realized; (ii) the Partnership
will be treated as a partnership for federal income tax purposes and not as a corporation and not as an association taxable as a corporation; (iii) to the extent the Partnership’s wells are timely drilled and its drilling costs are timely paid,
then subject to the limitations on deductions discussed in such opinion, the Partners will be entitled to claim as deductions their pro rata shares of the Partnership’s intangible drilling and development costs (“IDC”) paid in 2005;
(iv) for most Limited Partners, the Partnership’s operations will be considered a passive activity within the meaning of Section 469 of the Internal Revenue Code of 1986, as amended (the “Code”), and losses generated therefrom will be
limited by the passive activity provisions of the Code; (v) to the extent provided herein, the Partners’ distributive shares of Partnership tax items will be determined and allocated substantially in accordance with the terms of the Partnership
Agreement; and (vi) the Partnership will not be required to register with the Service as a tax shelter. 
  

 5 

 Due to the lack of authority regarding, or the essentially factual nature of certain issues, Conner &
Winters expresses no opinion on the following: (i) the impact of an investment in the Partnership on an investor’s alternative minimum tax liability; (ii) whether, under Code Section 183, the losses of the Partnership will be treated as derived
from “activities not engaged in for profit,” and therefore nondeductible from other gross income (due to the inherently factual nature of a Partner’s interest and motive in investing in the Partnership); (iii) whether any of the
Partnership’s properties will be considered “proven” for purposes of depletion deductions; (iv) whether any interest incurred by a Partner with respect to any borrowings incurred to purchase Units will be deductible or subject to
limitations on deductibility; and (v) whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership. 
  
 THIS MEMORANDUM CONTAINS AN EXPLANATION OF THE MORE SIGNIFICANT TERMS AND PROVISIONS OF THE AGREEMENT OF LIMITED
PARTNERSHIP WHICH IS ATTACHED AS EXHIBIT A. THE SUMMARY OF THE AGREEMENT CONTAINED IN THIS MEMORANDUM IS QUALIFIED IN ITS ENTIRETY BY SUCH REFERENCE AND ACCORDINGLY THE AGREEMENT SHOULD BE CAREFULLY REVIEWED AND CONSIDERED. 
  
 RISK FACTORS 
  
 Prospective purchasers of Units should carefully study the information
contained in this Memorandum and should make their own evaluations of the probability for the discovery of oil and natural gas through exploration. 
  
 INVESTMENT RISKS 
  
 Financial Risks of Drilling Operations 
  
 The Partnership will participate with the General Partner (including, with certain limited exceptions, other drilling programs sponsored by it, or UNIT) and, in some cases, other parties (“joint interest
parties”) in connection with drilling operations conducted on properties in which the Partnership has an interest. It is not anticipated that all such drilling operations will be conducted under turnkey drilling contracts and, thus, all of
the parties participating in the drilling operations on a particular property, including the Partnership, may be fully liable for their proportionate share of all costs of such operations even if the actual costs significantly exceed the original
cost estimates. Further, if any joint interest party defaults in its obligation to pay its share of the costs, the other joint interest parties may be required to fund the deficiency until, if ever, it can be collected from the defaulting party. As
a result of forced pooling or similar proceedings (see “COMPETITION, MARKETS AND REGULATION”), the Partnership may acquire larger fractional interests in Partnership Properties than originally anticipated and, thus, be required to bear a
greater share of the costs of operations. As a result of the foregoing, the Partnership could become liable for amounts significantly in excess of the amounts originally anticipated to be expended in connection with the operations and, in such
event, would have only limited means for providing needed additional funds (see “ADDITIONAL FINANCING”). Also, if a well is operated by a company which does not or cannot pay the costs and expenses of drilling or operating a Partnership
Well, the Partnership’s interest in such well may become subject to liens and claims of creditors who supplied services or materials in connection with such operations even though the Partnership may have previously paid its share of such costs
and expenses to the operator. If the operator is unable or unwilling to pay the amount due, the Partnership might have to pay its share of the amounts owing to such creditors in order to preserve its interest in the well which would mean that it
would, in effect, be paying for certain of such costs and expenses twice. 
  
 Dependence Upon General Partner 
  
 The
Limited Partners will acquire interests in the Partnership, not in the General Partner or UNIT. They will not participate in either increases or decreases in the General Partner’s or UNIT’s net worth or the value of its common stock.
Nevertheless, because the General Partner is primarily responsible for the proper conduct of the Partnership’s business and affairs and is obligated to provide certain funds that will be required in connection with its operations, a significant
financial reversal for the General Partner or UNIT could have an adverse effect on the Partnership and the Limited Partners’ interests therein. 
  

 6 

 Under the Partnership Agreement, UPC is designated as the General Partner of the Partnership and is given
the exclusive authority to manage and operate the Partnership’s business. See “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Power and Authority”. Accordingly, Limited Partners must rely solely on the General Partner to make all
decisions on behalf of the Partnership, as the Limited Partners will have no role in the management of the business of the Partnership. 
  
 The Partnership’s success will depend, in part, upon the management provided by the General Partner, the ability of the General Partner to select and
acquire oil and gas properties on which Partnership Wells capable of producing oil and natural gas in commercial quantities may be drilled, to fund the acquisition of revenue producing properties, and to market oil and natural gas produced from
Partnership Wells. 
  
 Conflicts of Interest 
  
 UNIT and its subsidiaries have engaged in oil and gas exploration and
development and in the acquisition of producing properties for their own account and as the sponsors of drilling and income programs formed with third party investors. It is anticipated that UNIT and its subsidiaries will continue to engage in such
activities. However, with certain exceptions, it is likely that the Partnership will participate as a working interest owner in all producing oil and gas leases acquired and in all oil and gas wells commenced by the General Partner or UNIT for its
own account during the period from January 1, 2005, if the Partnership is formed prior to such date, or from the date of the formation of the Partnership, if subsequent to January 1, 2005, through December 31, 2005 and, with certain limited
exceptions, will be a co-general partner of any drilling or income programs, or both, formed by the General Partner or UNIT in 2005. The General Partner will determine which prospects will be acquired or drilled. With respect to prospects to be
drilled, certain of the wells which are drilled for the separate account of the Partnership and the General Partner may be drilled on prospects on which initial drilling operations were conducted by UNIT or the General Partner prior to the formation
of the Partnership. Further, certain of the Partnership Wells will be drilled on prospects on which the General Partner and possibly future employee programs may conduct additional drilling operations in years subsequent to 2005. Except with respect
to its participation as a co-general partner of any drilling or income program sponsored by the General Partner or UNIT, the Partnership will have an interest only in those wells begun in 2005 and will have no rights in production from wells
commenced in years other than 2005. Likewise, if additional interests are acquired in wells participated in by the Partnership after 2005, the Partnership will generally not be entitled to participate in the acquisition of such additional interests.
See “CONFLICTS OF INTEREST — Acquisition of Properties and Drilling Operations.” 
  
 The Partnership may enter into contracts for the drilling of some or all of the Partnership Wells with affiliates of the General Partner. Likewise the
Partnership may sell or market some or all of its natural gas production to an affiliate of the General Partner. These contracts may not necessarily be negotiated on an arm’s - length basis. The General Partner is subject to a conflict of
interest in selecting an affiliate of the General Partner to drill the Partnership Wells and/or market the natural gas therefrom. The compensation under these contracts will be determined at the time of entering into each such contract, and the
costs to be paid thereunder or the sale price to be received will be one which is competitive with the costs charged or the prices paid by unaffiliated parties in the same geographic region. The General Partner will make the determination of what
are competitive rates or prices in the area. No provision has been made for an independent review of the fairness and reasonableness of such compensation. See “CONFLICTS OF INTERESTS — Transactions with the General Partner or
Affiliates.” 
  
 Prohibition on Transferability; Lack of Liquidity

  
 Except for certain transfers (i) to the General
Partner, (ii) to or for the benefit of the transferor Limited Partner or members of his or her immediate family sharing the same residence, and (iii) by reason of death or operation of law, a Limited Partner may not transfer or assign Units. The
General Partner has agreed, however, that it will, if requested at any time after December 31, 2006, buy Units for prices determined either by an independent petroleum engineering firm or the General Partner pursuant to a formula described under
“TERMS OF THE OFFERING — Right of Presentment.” This obligation of the General Partner to purchase Units when requested is limited and does not assure the liquidity of a Limited Partner’s investment, and the price received may be
less than if the Limited Partner continued to hold his or her Units. In addition, similar commitments have been made and may hereafter be made to investors in other oil and gas drilling, income and employee programs 

  

 7 

 
sponsored by the General Partner or UNIT. There can be no assurance that the General Partner will have the financial resources to honor its repurchase
commitments. See “TERMS OF THE OFFERING — Right of Presentment.” 
  
 Delay of Cash Distributions 
  
 For income
tax purposes, a Limited Partner must report his or her distributive (allocated) share of the income, gains, losses and deductions of the Partnership whether or not cash distributions are made. No cash distributions are expected to be made earlier
than the first quarter of 2006. In addition, to the extent that the Partnership uses its revenues to repay borrowings or to finance its activities (see “ADDITIONAL FINANCING”), the funds available for cash distributions by the Partnership
will be reduced or may be unavailable. It is possible that the amount of tax payable by a Limited Partner on his or her distributive share of the income of the Partnership will exceed his or her cash distributions from the Partnership. See
“FEDERAL INCOME TAX CONSIDERATIONS.” 
  
 If and the date
any distributions commence and their subsequent timing or amount cannot be accurately predicted. The decision as to whether or not the Partnership will make a cash distribution at any particular time will be made solely by the General Partner.

  
 Limitations on Voting and Other Rights of Limited Partners

  
 The Agreement, as permitted under the Oklahoma
Revised Uniform Limited Partnership Act (the “Act”), eliminates or limits the rights of the Limited Partners to take certain actions, such as: 
  

	 	•	 	withdrawing from the Partnership, 

  

	 	•	 	transferring Units without restrictions, or 

  

	 	•	 	consenting to or voting upon certain matters such as: 

	 	(i)	admitting a new General Partner, 

  

	 	(ii)	admitting Substituted Limited Partners, and 

  

	 	(iii)	dissolving the Partnership. 

  
 Furthermore, the Agreement imposes restrictions on the exercise of voting rights granted to Limited Partners. See “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Voting Rights.” Without the provisions
to the contrary which are contained in the Agreement, the Act provides that certain actions can be taken only with the consent of all Limited Partners. Those provisions of the Agreement which provide for or require the vote of the Limited Partners,
generally permit the approval of a proposal by the vote of Limited Partners holding a majority of the outstanding Units. See “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Voting Rights.” Thus, Limited Partners who do not agree with
or do not wish to be subject to the proposed action may nevertheless become subject to the action if the required majority approval is obtained. Notwithstanding the rights granted to Limited Partners under the Agreement and the Act, the General
Partner retains substantial discretion as to the operation of the Partnership. 
  
 Rollup or Consolidation of Partnership 
  
 Under the terms of the Agreement, at any time two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner is authorized to cause the
Partnership to transfer its assets to, or to merge or consolidate with, another partnership or a corporation or other entity for the purpose of combining the oil and gas properties and other assets of the Partnership with those of other partnerships
formed for investment or participation by the employees, directors and/or consultants of UNIT or any of its subsidiaries. Such transfer or combination may be effected without the vote, approval or consent of the Limited Partners. In such event, the
Limited Partners will receive interests in the transferee or resulting entity which will mean that they will most likely participate in the results of a larger number of properties but will have proportionately smaller allocable interests therein.
Any such transaction is required to be effected in a manner which UNIT and the General Partner believe is fair and equitable to the 

  

 8 

 
Limited Partners but there can be no assurance that such transaction will in fact be in the best interests of the Limited Partners. Limited Partners have no
dissenters’ or appraisal rights under the terms of the Agreement or the Act. Such a transaction would result in the termination and dissolution of the Partnership. While there can be no assurance that the Partnership will participate in such a
transaction, the General Partner currently anticipates that the Partnership will, at the appropriate time, be involved in such a transaction. See “TERMS OF OFFERING,” and “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT.”

  
 Partnership Borrowings 
  
 The General Partner has the authority to cause the Partnership to borrow
funds to pay certain costs of the Partnership. While the use of financing to preserve the Partnership’s equity in oil and gas properties will be intended to increase the Partnership’s profits, such financing could have the effect of
increasing the Partnership’s losses if the Partnership is unsuccessful. In addition, the Partnership may have to mortgage its oil and gas properties and other assets in order to obtain additional financing. If the Partnership defaults on such
indebtedness, the lender may foreclose and the Partnership could lose its investment in such oil and gas properties and other assets. See “ADDITIONAL FINANCING — Partnership Borrowings.” 
  
 Limited Liability 
  
 Under the Act a Limited Partner’s liability for the obligations of the
Partnership is limited to such Limited Partner’s Capital Contribution and such Limited Partner’s share of Partnership assets. In addition, if a Limited Partner receives a return of any part of his or her Capital Contribution, such Limited
Partner is generally liable to the Partnership for a period of one year thereafter (or six years in the event such return is in violation of the Agreement) for the amount of the returned contribution. A Limited Partner will not otherwise be liable
for the obligations of the Partnership unless, in addition to the exercise of his or her rights and powers as a Limited Partner, such Limited Partner participates in the control of the business of the Partnership. 
  
 The Agreement provides that by a vote of a majority in interest, the Limited
Partners may effect certain changes in the Partnership such as termination and dissolution of the Partnership and amendment of the Agreement. The exercise of any of these and certain other rights is conditioned upon receipt of an opinion by Conner
& Winters for the Limited Partners or an order or judgment of a court of competent jurisdiction to the effect that the exercise of such rights will not result in the loss of the limited liability of the Limited Partners or cause the Partnership
to be classified as an association taxable as a corporation (see “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Amendments” and “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Termination”). As a result of certain
judicial opinions it is not clear that these rights will ever be available to the Limited Partners. Nevertheless, in spite of the receipt of any such opinion or judicial order, it is still possible that the exercise of any such rights by the Limited
Partners may result in the loss of the Limited Partners’ limited liability. The Partnership will be governed by the Act. The Act expressly permits limited partners to vote on certain specified partnership matters without being deemed to be
participating in the control of the Partnership’s business and, thus, should result in greater certainty and more easily obtainable opinions of Conner & Winters regarding the exercise of most of the Limited Partners’ rights.

  
 If the Partnership is dissolved and its business is not to be
continued, the Partnership will be wound up. In connection with the winding up of the Partnership, all of its properties may be sold and the proceeds thereof credited to the accounts of the Partners. Properties not sold will, upon termination of the
Partnership, be distributed to the Partners. The distribution of Partnership Properties to the Limited Partners would result in their having unlimited liability with respect to such properties. See “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT
— Limited Liability.” 
  
 Partnership Acting as Co-General Partner

  
 It is anticipated that the Partnership will serve as
a co-general partner in any drilling or income programs formed by the General Partner or UNIT during 2005. See “PROPOSED ACTIVITIES.” Accordingly, the Partnership generally will be liable for the obligation and recourse liabilities of any
such drilling or income program formed. While a Limited Partner’s liability for such claims will be limited to such Limited Partners Capital Contribution and share of Partnership assets, such claims if satisfied from the Partnership’s
assets could adversely affect the operations of the Partnership. 
  

 9 

 Past-Due Installments; Acceleration; Additional Assessments 
  
 Installments and Additional Assessments (see “ADDITIONAL
FINANCING”) are legally binding obligations and past-due amounts will bear interest at the rate set forth in the Agreement; provided, however, that if the General Partner determines that the total Aggregate Subscription is not required to fund
the Partnership’s business and operations, then the General Partner may, at its sole option, elect to release the Limited Partners from their obligation to pay one or more Installments and amend any relevant Partnership documents accordingly.
It is anticipated that the total Aggregate Subscription will be required to fund the Partnership’s business and operations. In the event an Installment is not paid when due and the General Partner has not released the Limited Partners from
their obligation to pay such Installment, then the General Partner may, at its sole option, purchase all Units of the director or employee who fails to pay such Installment, at a price equal to the amount of the prior Installments paid by such
person. The General Partner may also bring legal proceedings to collect any unpaid Installments not waived by it or Additional Assessments. In addition, as indicated under “TERMS OF THE OFFERING — Payment for Units; Delinquent
Installment,” if an employee’s employment with or position as a director of the General Partner, UNIT or any affiliate thereof is terminated other than by reason of Normal Retirement (see “GLOSSARY”), death or disability prior to
the time the full amount of the subscription price for his or her Units has been paid, all unpaid Installments not waived by the General Partner as described above will become due and payable upon such termination. 
  
 Partnership Funds 
  
 Except for Capital Contributions, Partnership funds are expected to be
commingled with funds of the General Partner or UNIT. Thus, Partnership funds could become subject to the claims of creditors of the General Partner or UNIT. The General Partner believes that its assets and net worth are such that the risk of loss
to the Partnership by virtue of such fact is minimal but there can be no assurance that the Partnership will not suffer losses of its funds to creditors of the General Partner or UNIT. 
  
 Compliance With Federal and State Securities Laws 
  
 This offering has not been registered under the Securities Act of 1933, as amended, in reliance upon exemptive provisions of
said act. Further, these interests are being sold pursuant to exemptions from registration in the various states in which they are being offered and may be subject to additional restrictions in such jurisdictions on transfer. There is no assurance
that the offering presently qualifies or will continue to qualify under such exemptive provisions due to, among other things, the adequacy of disclosure and the manner of distribution of the offering, the existence of similar offerings conducted by
the General Partner or UNIT or its affiliates in the past or in the future, a failure or delay in providing notices or other required filings, the conduct of other oil and gas activities by the General Partner or UNIT and its affiliates or the
change of any securities laws or regulations. 
  
 If and to the
extent suits for rescission are brought and successfully concluded for failure to register this offering or other offerings under the Securities Act of 1933, as amended, or state securities acts, or for acts or omissions constituting certain
prohibited practices under any of said acts, both the capital and assets of the General Partner and the Partnership could be adversely affected, thus jeopardizing the ability of the Partnership to operate successfully. Further, the time and capital
of the General Partner could be expended in defending an action by investors or by state or federal authorities even where the Partnership and the General Partner are ultimately exonerated. 
  
 Title To Properties 
  
 The Partnership Agreement empowers the General Partner, UNIT or any of their
affiliates, to hold title to the Partnership Properties for the benefit of the Partnership. As such it is possible that the Partnership Properties could be subject to the claims of creditors of the General Partner. The General Partner is of the
opinion that the likelihood of the occurrence of such claims is remote. However, the Partnership Property could be subject to claims and litigation in the event that the General Partner failed to pay its debts or became subject to the claims of
creditors. 
  

 10 

 Use of Partnership Funds to Exculpate and Indemnify the General Partner 
  
 The Agreement contains certain provisions which are intended to limit the
liability of the General Partner and its affiliates for certain acts or omissions within the scope of the authority conferred upon them by the Agreement. In addition, under the Agreement, the General Partner will be indemnified by the Partnership
against losses, judgments, liabilities, expenses and amounts paid in settlement sustained by it in connection with the Partnership so long as the losses, judgments, liabilities, expenses or amounts were not the result of gross negligence or willful
misconduct on the part of the General Partner. See “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Exculpation and Indemnification of the General Partner.” 
  
 The Partnership Agreement May Limit the Fiduciary Obligation of the General Partner to the Partnership and the Limited Partners

  
 The Agreement contains certain provisions which
modify what would otherwise be the applicable Oklahoma law relating to the fiduciary standards of the General Partner to the Limited Partners. The fiduciary standards in the Agreement could be less advantageous to the Limited Partners and more
advantageous to the General Partner than the corresponding fiduciary standards otherwise applicable under Oklahoma law (although there are very few legal precedents clarifying exactly what fiduciary standards would otherwise be applicable under
Oklahoma law). The purchase of Units may be deemed as consent to the fiduciary standards set forth in the Agreement. See “FIDUCIARY RESPONSIBILITY.” As a result of these provisions in the Agreement, the Limited Partners may find it more
difficult to hold the General Partner responsible for acting in the best interest of the Partnership and the Limited Partners than if the fiduciary standards of the otherwise applicable Oklahoma law governed the situation. 
  
 TAX STATUS AND TAX RISKS 
  
 It is possible that the tax treatment currently available with respect to
oil and gas exploration and production will be modified or eliminated on a retroactive or prospective basis by legislative, judicial, or administrative actions. The limited tax benefits associated with oil and gas exploration do not eliminate the
inherent economic risks. See “Federal Income Tax Considerations.” 
  
 Partnership Classification 
  
 Conner
& Winters has rendered its opinion that the Partnership will be classified for federal income tax purposes as a partnership and not as a corporation, an association taxable as a corporation or a “publicly traded partnership.” Such
opinion is not binding on the Service or the courts. If the Partnership were classified as a corporation, association taxable as a corporation or publicly traded partnership, any income, gain, loss, deduction, or credit of the Partnership would
remain at the entity level, and not flow through to the Partners, the income of the Partnership would be subject to corporate tax rates at the entity level and distributions to the Partners could be considered dividend distributions. See
“Federal Income Tax Considerations—General Tax Effects of Partnership Structure.” 
  
 Limited Partner Interests 
  
 An investment as a Limited Partner may not be advisable for a person who does not anticipate having substantial current taxable income from passive trade or business activities (not counting dividend or interest
income). Most Limited Partners will be subject to the “passive activity loss” rules and will be unable to use passive losses generated by the Partnership until and unless he or she has realized “passive income”. 
  
 Tax Liabilities in Excess of Cash Distributions 
  
 A Partner must include in his or her own income tax return his or her share
of the items of the Partnership’s income, gain, profit, loss, and deductions whether or not cash proceeds are actually distributed to the Partner to pay any tax resulting from the Partnership’s activities. For example, income from the
Partnership’s sale of oil and gas production will be taxable to Partners as ordinary income subject to depletion and other deductions whether or not the proceeds from such sale are actually distributed (for example, where Partnership income is
used to repay Partnership indebtedness). 
  

 11 

 Items Not Covered by the Tax Opinion 
  
 Due to the lack of authority regarding, or the essentially factual nature of certain issues, Conner & Winters has
expressed no opinion as to the following: (i) the impact of an investment in the Partnership on an investor’s alternative minimum tax liability; (ii) whether any of the Partnership’s properties will be considered “proven” for
purposes of depletion deductions; and (iii) whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership. 
  
 The determination of various of the above-referenced issues is dependent on
facts not currently available. Therefore, Conner & Winters is unable to render an opinion at this time with respect to such issues. Also, the unknown facts with respect to the various issues referred to above will vary from Partner to Partner
and will result in different tax consequences and burdens for individual Partners. 
  
 Prospective investors should recognize that an opinion of legal counsel merely represents such counsel’s best legal judgment under existing statutes, judicial decisions, and administrative regulations and
interpretations. There can be no assurance that deductions claimed by the Partnership in reliance upon the opinion of Conner & Winters will not be challenged successfully by the Service. 
  
 OPERATIONAL RISKS 
  
 Risks Inherent in Oil and Gas Operations 
  
 The Partnership will be participating with the General Partner in acquiring producing oil and gas leases and in the drilling
of those oil and gas wells commenced by the General Partner from the later of January 1, 2005 or the time the Partnership is formed through December 31, 2005 and, with certain limited exceptions, serving as a co-general partner of any oil and gas
drilling or income programs, or both, formed by the General Partner or UNIT during 2005. 
  
 All drilling to establish productive oil and natural gas properties is inherently speculative. The techniques presently available to identify the existence and location of pools of oil and natural gas are indirect,
and, therefore, a considerable amount of personal judgment is involved in the selection of any prospect for drilling. The economics of oil and natural gas drilling and production are affected or may be affected in the future by a number of factors
which are beyond the control of the General Partner, including (i) the general demand in the economy for energy fuels, (ii) the worldwide supply of oil and natural gas, (iii) the price of, as well as governmental policies with respect to, oil
imports, (iv) potential competition from competing alternative fuels, (v) governmental regulation of prices for oil and natural gas production, gathering and transportation, (vi) state regulations affecting allowable rates of production, well
spacing and other factors, and (vii) availability of drilling rigs, casing and other necessary goods and services. See “COMPETITION, MARKETS AND REGULATION.” The revenues, if any, generated from Partnership operations will be highly
dependent upon the future prices and demand for oil and natural gas. The factors enumerated above affect, and will continue to affect, oil and natural gas prices. Recently, prices for oil and natural gas have fluctuated over a wide range.

  
 Operating and Environmental Hazards 
  
 Operating hazards such as fires, explosions, blowouts, unusual formations,
formations with abnormal pressures and other unforeseen conditions are sometimes encountered in drilling wells. On occasion, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce the
funds available for exploration and development or result in loss of Partnership Properties. The Partnership will attempt to maintain customary insurance coverage, but the Partnership may be subject to liability for pollution and other damages or
may lose substantial portions of its properties due to hazards against which it cannot insure or against which it may elect not to insure due to unreasonably high or prohibitive premium costs or for other reasons. The activities of the Partnership
may expose it to potential liability for pollution or other damages under laws and regulations relating to environmental matters (see “Government Regulation and Environmental Risks” below). 
  
 Competition 
  
 The oil and gas industry is highly competitive. The Partnership will be involved in intense competition for the acquisition
of quality undeveloped leases and producing oil and gas properties. There can be no assurance 

  

 12 

 
that a sufficient number of suitable oil and gas properties will be available for acquisition or development by the Partnership. The Partnership will be
competing with numerous major and independent companies which possess financial resources and staffs larger than those available to it. The Partnership, therefore, may be unable in certain instances to acquire desirable leases or supplies or may
encounter delays in commencing or completing Partnership operations. 
  
 Markets for Oil and Natural Gas Production 
  
 Historically (prior to the early 1980s), world oil prices were established and maintained largely as a result of the actions of members of OPEC to limit, and maintain a base price for, their oil production. Until recently, however, members
of OPEC were unable to agree to and maintain price and production controls, which resulted in significant downward pressure on oil prices. Commencing in early 2001, OPEC members were able to reach agreement on oil production levels which has
contributed to a rise in oil prices. Although future levels of production by the members of OPEC or the degree to which oil prices will be affected thereby cannot be predicted, it is possible that prices for oil produced in the future will be higher
or lower than those currently available. There can be no assurance that the oil that the Partnership produces can be marketed on favorable price and other contractual terms. See “COMPETITION, MARKETS AND REGULATION — Marketing of
Production.” 
  
 The natural gas market is also unsettled due
to a number of factors. In the past, production from natural gas wells in some geographic areas of the United States was curtailed for considerable periods of time due to a lack of market demand. Over the past several years demand for natural gas
has increased greatly limiting the number of wells being shut in for lack of demand. It is possible, however, that Partnership Wells may in the future be shut-in or that natural gas will be sold on terms less favorable than might otherwise be
obtained should demand for gas lessen in the future. Competition for available markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. In recent years, significant court decisions and regulatory changes
have affected the natural gas markets. As a result of such court decisions, regulatory changes and unsettled market conditions, natural gas regulations may be modified in the future and may be subject to further judicial review or invalidation. The
combination of these factors, among others, makes it particularly difficult to estimate accurately future prices of natural gas, and any assumptions concerning future prices may prove incorrect. Natural gas surpluses could result in the
Partnership’s inability to market natural gas profitably, causing Partnership Wells to curtail production and/or receive lower prices for its natural gas, situations which would adversely affect the Partnership’s ability to make cash
distributions to its participants. See “COMPETITION, MARKETS AND REGULATION.” 
  
 In the event that the Partnership discovers or acquires natural gas reserves, there may be delays in commencing or continuing production due to the need for gathering and pipeline facilities, contract negotiation with
the available market, pipeline capacities, seasonal takes by the gas purchaser or a surplus of available gas reserves in a particular area. 
  
 Government Regulation and Environmental Risks 
  
 The oil and gas business is subject to pervasive government regulation under which, among other things, rates of production from producing properties may
be fixed and the prices for gas produced from such producing properties may be impacted. It is possible that these regulations pertaining to rates of production could become more pervasive and stringent in the future. The activities of the
Partnership may expose it to potential liability under laws and regulations relating to environmental matters which could adversely affect the Partnership. Compliance with these laws and regulations may increase Partnership costs, delay or prevent
the drilling of wells, delay or prevent the acquisition of otherwise desirable producing oil and gas properties, require the Partnership to cease operations in certain areas, and cause delays in the production of oil and gas. See “COMPETITION,
MARKETING AND REGULATION.” 
  
 Leasehold Defects 
  
 In certain instances, the Partnership may not be able to obtain a title
opinion or report with respect to a producing property that is acquired. Consequently, the Partnership’s title to any such property may be uncertain. Furthermore, even if certain technical defects do appear in title opinions or reports with
respect to a particular property, the General Partner, in its sole discretion, may determine that it is in the best interest of the Partnership to acquire such property without taking any curative action. 
  

 13 

 TERMS OF THE OFFERING 
  
 General 
  

	 	•	 	600 Maximum Units; 50 Minimum Units 

  

	 	•	 	$1,000 Units; Minimum subscription: $2,000 

  

	 	•	 	Minimum Partnership: $50,000 in subscriptions 

  

	 	•	 	Maximum Partnership: $600,000 in subscriptions 

  
 Limited Partnership Interests 
  
 The Partnership hereby offers to certain employees (described under “Subscription Rights” below) and directors of UNIT and its subsidiaries an
aggregate of 600 Units. The purchase price of each Unit is $1,000, and the minimum permissible purchase by any eligible subscriber is two Units ($2,000). See “Subscription Rights” below for the maximum number of Units that may be acquired
by subscribers. 
  
 The Partnership will be formed as an Oklahoma
limited partnership upon the closing of the offering of Units made by this Memorandum. The General Partner will be Unit Petroleum Company (the “General Partner”, or “UPC”), an Oklahoma corporation. Partnership
operations will be conducted from the General Partner’s offices, the address of which is 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136, telephone (918) 493-7700. 
  
 The offering of Units will be closed on January 21, 2005 unless extended by the General Partner for up to 30 days, and all
Units subscribed will be issued on the Effective Date. The offering may be withdrawn by the General Partner at any time prior to such date if it believes it to be in the best interests of the eligible employees and Directors or the General Partner
not to proceed with the offering. 
  
 If at least 50 Units
($50,000) are not subscribed prior to the termination of the offering, the Partnership will not commence business. The General Partner may, on its own accord, purchase Units and, in such capacity, will enjoy the same rights and obligations as other
Limited Partners, except the General Partner will have unlimited liability. The General Partner may, in its discretion, purchase Units sufficient to reach the minimum Aggregate Subscription ($50,000). Because the General Partner or its affiliates
might benefit from the successful completion of this offering (see “PARTICIPATION IN COSTS, AND REVENUES” and “COMPENSATION”), investors should not expect that sales of the minimum Aggregate Subscription indicate that such sales
have been made to investors that have no financial or other interest in the offering or that have otherwise exercised independent investment discretion. Further, the sale of the minimum Aggregate Subscription is not designed as a protection to
investors to indicate that their interest is shared by other unaffiliated investors and no investor should place any reliance on the sale of the minimum Aggregate Subscription as an indication of the merits of this offering. Units acquired by the
General Partner will be for investment purposes only without a present intent for resale and there is no limit on the number of Units that may be acquired by it. 
  
 Subscription Rights 
  
 Units are offered only to persons who are salaried employees of UNIT or its subsidiaries at the date of formation of the Partnership and whose annual base
salaries for 2004 (excluding bonuses) have been set at $36,000 or more and to directors of UNIT. Only employees and directors who are U.S. citizens are eligible to participate in the offering. In addition, employees and directors must be able to
bear the economic risks of an investment in the Partnership and must have sufficient investment experience and expertise to evaluate the risks and merits of such an investment. See “PLAN OF DISTRIBUTION — Suitability of Investors.”

  

 14 

 Eligible employees and directors are restricted as to the number of Units they may purchase in the
offering. The maximum number of Units which can be acquired by any employee is that number of whole Units which can be purchased with an amount which does not exceed one-half of the employee’s base salary for 2004. Each director of UNIT may
subscribe for a maximum of 250 Units (maximum investment of $250,000). At December 9, 2004 there were approximately 376 people eligible to purchase Units. 
  
 Eligible employees and directors may acquire Units through a corporation or other entity in which all of the beneficial interests are owned by them or
permitted assignees (see “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Transferability of Interests”); provided that such employees or Directors will be jointly and severally liable with such entity for payment of the Capital
Subscription. 
  
 If all eligible employees and directors
subscribed for the maximum number of Units, the Units would be oversubscribed. In that event, Units would be allocated among the respective subscribers in the proportion that each subscription amount bears to total subscriptions obtained.

  
 No employee is obligated to purchase Units in order to remain
in the employ of UNIT, and the purchase of Units by any employee will not obligate UNIT to continue the employment of such employee. Units may be subscribed for by the spouse or a trust for the minor children of eligible employees and directors.

  
 Payment for Units; Delinquent Installment 
  
 The Capital Subscriptions of the Limited Partners will be payable either (i)
in four equal Installments, the first of such Installments being due on March 15, 2005 and the remaining three of such Installments being due on June 15, September 15, and December 15, 2005, respectively, or (ii) by employees so electing in the
space provided on the Subscription Agreement, through equal deductions from 2005 salary paid to the employee by the General Partner, UNIT or its subsidiaries commencing immediately after formation of the Partnership. If an employee or director who
has subscribed for Units (either directly or through a corporation or other entity) ceases to be employed by or serve as a director of the General Partner, UNIT or any of its subsidiaries for any reason other than death, disability or Normal
Retirement prior to the time the full amount of all Installments not waived by the General Partner as described below are due, then the due date for any such unpaid Installments shall be accelerated so that the full amount of his or her unpaid
Capital Subscription will be due and payable on the effective date of such termination. 
  
 Each Installment will be a legally binding obligation of the Limited Partner and any past due amounts will bear interest at an annual rate equal to two percentage points in excess of the prime rate of interest of Bank
of Oklahoma, N.A., Tulsa, Oklahoma; provided, however, that if the General Partner determines that the total Aggregate Subscription is not required to fund the Partnership’s business and operations, then the General Partner may, at its sole
option, elect to release the Limited Partners from their obligation to pay one or more Installments. If the General Partner elects to waive the payment of an Installment, it will notify all Limited Partners promptly in writing of its decision and
will, to the extent required, amend the certificate of limited partnership and any other relevant Partnership documents accordingly. It is currently anticipated that the total Aggregate Subscription will be required, however, to fund the
Partnership’s business and operations. 
  
 In the event a
Limited Partner fails to pay any Installment when due and the General Partner has not released the Limited Partners from their obligation to pay such Installment, then the General Partner, at its sole option and discretion, may elect to purchase the
Units of such defaulting Limited Partner at a price equal to the total amount of the Capital Contributions actually paid into the Partnership by such defaulting Limited Partner, less the amount of any Partnership distributions that may have been
received by him or her. Such option may be exercised by the General Partner by written notice to the Limited Partner at any time after the date that the unpaid Installment was due and will be deemed exercised when the amount of the purchase price is
first tendered to the defaulting Limited Partner. The General Partner may, in its discretion, accept payments of delinquent Installments not waived by it but will not be required to do so. 
  
 In the event that the General Partner elects to purchase the Units of a
defaulting Limited Partner, it must pay into the Partnership the amount of the delinquent Installment (excluding any interest that may have accrued thereon) and pay each additional Installment, if any, payable with respect to such Units as it
becomes due. By virtue of such purchase, the General Partner will be allocated all Partnership Revenues, be charged with all Partnership costs and expenses attributable to such Units and will enjoy the same rights and obligations as other Limited
Partners, except the General Partner will have unlimited liability. 
  
  

 15 

 Right of Presentment 
  
 After December 31, 2006, and annually thereafter, Limited Partners will have the right to present their Units to the General
Partner for purchase. The General Partner will not be obligated to purchase more than 20% of the then outstanding Units in any one calendar year. The purchase price to be paid for the Units of any Limited Partner presenting them for purchase will be
based on the net asset value of the Partnership which shall be equal to: 
  

	 	(1)	The value of the proved reserves attributable to the Partnership Properties, determined as set forth below; plus 

  

	 	(2)	The estimated salvage value of tangible equipment installed on Partnership Wells less the costs of plugging and abandoning the wells, both discounted at the rate utilized to
determine the value of the Partnership’s reserves as set forth below; plus 

  

	 	(3)	The lower of cost or fair market value of all Partnership Properties to which proved reserves have not been attributed but which have not been condemned, as determined by an
independent petroleum engineering firm or the General Partner, as the case may be; plus 

  

	 	(4)	Cash on hand; plus 

  

	 	(5)	Prepaid expenses and accounts receivable (less a reasonable reserve for doubtful accounts); plus 

  

	 	(6)	The estimated market value of all other Partnership assets not included in (1) through (5) above, determined by the General Partner; MINUS 

  

	 	(7)	An amount equal to all debts, obligations and other liabilities of the Partnership. 

  
 The price to be paid for each Limited Partner’s interest of the net asset value will be his or her proportionate share of such net
asset value less 75% of the amount of any distributions received by him or her which are attributable to the sales of the Partnership production since the date as of which the Partnership’s proved reserves are estimated. 
  
 The value of the proved reserves attributable to Partnership Properties will
be determined as follows: 
  

	 	(i)	First, the future net revenues from the production and sale of the proved reserves will be estimated as of the end of the calendar year in which presentment is made based on an
independent engineering firm’s report and its determinations of the prices to be used as well as the escalations, if any, of such prices and cost or, if no report was made, as determined by the General Partner; 

  

	 	(ii)	Next, the future net revenues from the production and sale of proved reserves as determined above will be discounted at an annual rate which is one percentage point higher than the
prime rate of interest being charged by the Bank of Oklahoma, N.A., Tulsa, Oklahoma, or any successor bank, as of the date such reserves are estimated; and 

  

	 	(iii)	Finally, the total discounted value of the future net revenues from the production and sale of proved reserves will be reduced by an additional 25% to take into account the risks
and uncertainties associated with the production and sale of the reserves and other unforeseen uncertainties. 

  
 A Limited Partner who elects to have his or her Units purchased by the General Partner should be aware that estimates of future net recoverable reserves
of oil and gas and estimates of future net revenues to be received therefrom are based on a great many factors, some of which, particularly future prices of production, are usually variable and uncertain and are always determined by predictions of
future events. Accordingly, it is common for the actual production and revenues received to vary from earlier estimates. Estimates made in the first few years 

  

 16 

 
of production from a property will be based on relatively little production history and will not be as reliable as later estimates based on longer production
history. As a result of all the foregoing, reserve estimates and estimates of future net revenues from production may vary from year to year. 
  
 This right of presentment may be exercised by written notice from a Limited Partner to the General Partner. The sale will be effective as of the close of
business on the last day of the calendar year in which such notice is given or, at the General Partner’s election, at 7:00 A.M. on the following day. Within 120 days after the end of the calendar year, the General Partner will furnish each
Limited Partner who gave such notice during the calendar year a statement showing the cash purchase price which would be paid for the Limited Partner’s interest as of December 31 of the preceding year, which statement will include a summary of
estimated reserves and future net revenues and sufficient material to reveal how the purchase price was determined. The Limited Partner must, within 30 days after receipt of such statement, reaffirm his or her election to sell to the General
Partner. 
  
 As noted above, the General Partner will not be
obligated to purchase in any one calendar year more than 20% of the Units in the Partnership then outstanding. Moreover, the General Partner will not be obligated to purchase any Units pursuant to such right if such purchase, when added to the total
of all other sales, exchanges, transfers or assignments of Units within the preceding 12 months, would result in the Partnership being considered to have terminated within the meaning of Section 708 of the Code or would cause the Partnership to lose
its status as a partnership for federal income tax purposes. If more than the number of Units which may be purchased are tendered in any one year, the Limited Partners from whom the Units are to be purchased will be determined by lot. Any Units
presented but not purchased with respect to one year will have priority for such purchase the following year. 
  
 The General Partner does not intend to establish a cash reserve to fund its obligation to purchase Units, but will use funds provided by its operations or
borrowed funds (if available), using its assets (including such Units purchased or to be purchased from Limited Partners) as collateral to fund such obligations. However, there is no assurance that the General Partner will have sufficient financial
resources to discharge its obligations. 
  
 Rollup or Consolidation of
Partnership 
  
 The Agreement provides that two years or
more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner may, without the vote, consent or approval of the Limited Partners, cause all or substantially all of
the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or consolidated with, another partnership or a corporation, trust or other entity for the purpose of combining the
assets of two or more of the oil and gas partnerships formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries; provided, however, that the valuation of the oil and gas properties and other
assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a manner which the General Partner and UNIT believe is fair and equitable to the Limited Partners. As a consequence
of any such transfer or combination, the Partnership shall be dissolved and terminated and the Limited Partners shall receive partnership interests, stock or other equity interests in the transferee or resulting entity. Any such action will cause
the Limited Partners’ attributable interest in the Partnership Properties to be diluted but it will also provide them with attributable interests in the properties and other assets of the other partnerships participating in the consolidation.
It also may reduce somewhat the amount of their attributable shares of the direct and indirect costs of administering the Partnership. See “RISK FACTORS — Investment Risks - Roll-Up or Consolidation of Partnership.” 
  
 ADDITIONAL FINANCING 
  
 The General Partner will use its best efforts, consistent with Partnership
objectives, to acquire Productive properties and complete the Partnership’s drilling and development operations before the Aggregate Subscription has been fully expended or committed. However, funds in addition to the Aggregate Subscription may
be required to pay costs and expenses which are chargeable to the Limited Partners. In those instances described below, the General Partner may call for Additional Assessments or may apply Partnership Revenue allocable to the Limited Partners in
payment and satisfaction of such costs or the General Partner may, but shall not be required to, fund the deficiency with Partnership borrowings to be repaid with Partnership Revenue. 
  
  

 17 

 Additional Assessments 
  
 When the Aggregate Subscription has been fully expended or committed, the General Partner may make one or more calls for any
portion or all of the maximum Additional Assessments of $100 per Unit. However, no Additional Assessments may be required before the General Partner’s Minimum Capital Contribution has been fully expended. Such assessments may be used to pay the
Limited Partners’ share of the Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties which are chargeable to the Limited Partners. The amount of the Additional Assessment so called shall
be due and payable on or before such date as the General Partner may set in such call, which in no event will be earlier than thirty (30) days after the date of mailing of the call. The notice of the call for Additional Assessments will specify the
amount of the assessment being required, the intended use of such funds, the date on which the contributions are payable and describe the consequences of nonpayment. Although the Limited Partners who do not respond will participate in production, if
any, obtained from operations conducted with the proceeds from the aggregate Additional Assessments paid into the Partnership, the amount of the unpaid Additional Assessment shall bear interest at the annual rate equal to two (2) percentage points
in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time to time, until paid. The Partnership will have a lien on the defaulting Limited Partner’s interest in
the Partnership and the General Partner may retain Partnership Revenue otherwise available for distribution to the defaulting Limited Partner until an amount equal to the unpaid Additional Assessment and interest is received. Furthermore, the
General Partner may satisfy such lien by proceeding with legal action to enforce the lien and the defaulting Limited Partner shall pay all expenses of collection, including interest, court costs and a reasonable attorney’s fee. 
  
 Prior Programs 
  
 In the prior employee programs conducted by UNIT or the General Partner in each of the years 1984 through 2004, Additional
Assessments could be called for as provided herein. At September 30, 2004, there had been no calls for Additional Assessments in such programs. There can be no assurance, however, that Additional Assessments will not be required to pay Partnership
costs. 
  
 Partnership Borrowings 
  
 At any time after the General Partner’s Minimum Capital Contribution
has been fully expended, the General Partner may cause the Partnership to borrow funds for the purpose of paying Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties, which borrowings may be
secured by interests in the Partnership Properties and will be repaid, including interest accruing thereon, out of Partnership Revenue. The General Partner may, but is not required to, advance funds to the Partnership for the same purposes for which
Partnership borrowings are authorized. With respect to any such advances, the General Partner will receive interest in an amount equal to the lesser of the interest which would be charged to the Partnership by unrelated banks on comparable loans for
the same purpose or the General Partner’s interest cost with respect to such loan, where it borrows the same. No financing charges will be levied by the General Partner in connection with any such loan. If Partnership borrowings secured by
interests in the Partnership Wells and repayable out of Partnership Revenue cannot be arranged on a basis which, in the opinion of the General Partner, is fair and reasonable, and the entire sum required to pay such costs is not available from
Partnership Revenue, the General Partner may dispose of some or all of the Partnership Properties upon which such operations were to be conducted by sale, farm-out or abandonment. 
  
 If the Partnership requires funds to conduct Partnership operations during the period between any of the Installments due
from the Limited Partners, then, notwithstanding the foregoing, the General Partner shall advance funds to the Partnership in an amount equal to the funds then required to conduct such operations but in no event more than the total amount of the
Aggregate Subscription remaining unpaid. With respect to any such advances, the General Partner shall receive no interest thereon and no financing charges will be levied by the General Partner in connection therewith. The General Partner shall be
repaid out of the Installments thereafter paid into the capital of the Partnership when due. 
  
 The Partnership may attempt to finance any expenses in excess of the Partners’ Capital Subscriptions by the foregoing means and any other means which the General Partner deems in the best interests of the
Partnership, but the Partnership’s inability to meet such costs could result in the deferral of drilling operations or in the 

  

 18 

 
inability to participate in future drilling or in non-consent penalties pursuant to which co-owners of particular working interests recover several times the
amount which would have been funded by the Partnership in accordance with its ownership interest before the Partnership would participate in revenues. 
  
 The use of Partnership Revenue allocable to the Limited Partners to pay Partnership costs and expenses and to repay any Partnership borrowings will mean
that such revenue will not be available for distribution to the Limited Partners. Nonetheless, the Limited Partners may incur income tax liability by virtue of that revenue and, thus, may not receive distributions from the Partnership in amounts
necessary to pay such income tax. However, the use of such revenue to pay Partnership costs and expenses may generate additional deductions for the Limited Partners. 
  
 PLAN OF DISTRIBUTION 
  
 Units will be offered privately only to select persons who can demonstrate to the General Partner that they have both the economic means and investment
expertise to qualify as suitable investors. The Units will be offered and sold by the officers and directors of UPC or UNIT. 
  
 Suitability of Investors 
  
 Subscriptions should be made only by appropriate persons who can reasonably benefit from an investment in the Partnership. In this regard, a subscription
will generally be accepted only from a person who can represent that such person has (or in the case of a husband and wife, acting as joint tenants, tenants in common or tenants in the entirety, that they have) a net worth, including home,
furnishings and automobiles, of at least five times the amount of his or her Capital Subscription, and estimates that such person will have during the current year adjusted gross income in an amount which will enable him or her to bear the economic
risks of his or her investment in the Partnership. Such person must also demonstrate that he or she has sufficient investment experience and expertise to evaluate the risks and merits of an investment in the Partnership. 
  
 Participation in the Partnership is intended only for those persons willing
to assume the risk of a speculative, illiquid, long-term investment. Entitlement to and maintenance of the exemptions from registration provided by Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended, require the imposition of
certain limitations on the persons to whom offers may be made, and from whom subscriptions may be accepted. Therefore, this offering is limited to persons who, by virtue of investment acumen or financial resources, satisfy the General Partner that
they meet suitability standards consistent with the maintenance and preservation of the exemptions provided by Sections 3(b) and/or 4(2) and by the applicable rules and regulations of the Securities and Exchange Commission, as well as those
contained herein and in the Subscription Agreement. Persons offering interests shall sufficiently inquire of a prospective investor to be reasonably assured that such investor meets such acceptable standards. Suitability standards may also be
imposed by the regulatory authorities of the various states in which interests may be offered. 
  
  

 19 

 RELATIONSHIP OF THE PARTNERSHIP, 
 THE GENERAL PARTNER AND AFFILIATES 
  
 The following diagram depicts the primary relationships among the Partnership, the General Partner and certain of its affiliates. 
  
 UNIT CORPORATION 
  

			
	General Partner	 	 
	Unit Petroleum Company	 	Unit Drilling Company
		
	 Unit 2005 Employee Oil & Gas
 Limited Partnership
	 	 
		
	Limited Partners	 	 
	 Eligible Employees
 and
 Directors
	 	 

  
 PROPOSED ACTIVITIES

  
 General 
  
 The Partnership will, with certain limited exceptions, participate in all of
UNIT’s or UPC’s oil and gas activities commenced during 2005. The Partnership will acquire 1% of essentially all of UNIT’s interest in such activities. The activities will include (i) participating as a joint working interest owner
with UNIT or UPC in any producing leases acquired and in any wells commenced by UNIT or UPC other than as a general partner in a drilling or income program during 2004 and (ii) serving as a co-general partner in any drilling or income programs, or
both, formed by the General Partner or UNIT during 2005. 
  
 Acquisition of Properties and Drilling Operations. The Partnership will participate, to the extent of 1% of UPC or UNIT’s final interest in each well, as a fractional working interest holder in any producing leases
acquired and in any drilling operations conducted by UPC or UNIT for its own account which are acquired or commenced, respectively, from January 1, 2005, or the time of the formation of the Partnership if subsequent to January 1, 2005, until
December 31, 2005, except for wells, if any: 
  

	 	(i)	drilled outside the 48 contiguous United States; 

  

	 	(ii)	drilled as part of secondary or tertiary recovery operations which were in existence prior to formation of the Partnership; 

  

	 	(iii)	drilled by third parties under farm-out or similar arrangements with UNIT or the General Partner or whereby UNIT or the General Partner may be entitled to an overriding royalty,
reversionary or other similar interest in the production from such wells but is not obligated to pay any of the Drilling Costs thereof; 

  

	 	(iv)	acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies (However, this
exception may, at the discretion of Unit or the General Partner, be waived); or 

  

 20 

	 	(v)	with respect to which the General Partner does not believe that the potential economic return therefrom justifies the costs of participation by the Partnership.

  
 Instances referred to in (v) could occur when UNIT or one of its
subsidiaries agrees to participate in the ownership of a prospect for its own account in order to obtain the contract to drill the well thereon. There may be situations where the potential economic return of the well alone would not be sufficient to
warrant participation by UNIT but when considered in light of the revenues expected to be realized as a result of the drilling contract, such participation is desirable from UNIT’s standpoint. However, in such a situation, the Partnership would
not be entitled to any of the revenues generated by the drilling contract so its participation in the well would not be desirable. 
  
 For these purposes, the drilling of a well will be deemed to have commenced on the “spud date,” i.e., the date that the drilling rig is set up
and actual drilling operations are commenced. Any clearing or other site preparation operations will not be considered part of the drilling operations for these purposes. 
  
 Participation in Drilling or Income Programs. Except for certain limited exceptions it is anticipated that the
Partnership will participate with UPC or UNIT as a co-general partner of any drilling or income programs, or both, formed by UPC or UNIT and its affiliates during 2005. The Partnership will be charged with 1% of the total costs and expenses charged
to the general partners and allocated 1% of the revenues allocable to the general partners in any such program and UPC or UNIT will be charged with the remaining 99% of the general partners’ share of costs and expenses and allocated the
remaining 99% of the general partners’ share of program revenues. 
  
 UNIT or its affiliates formed drilling programs for outside investors from 1979 through 1984. In 1987, the Unit 1986 Energy Income Limited Partnership (the “1986 Energy Program”) was formed primarily to acquire interests in
producing oil and gas properties. See “PRIOR ACTIVITIES.” All of the programs were formed as limited partnerships and interests in all of the programs other than the Unit 1979 Oil and Gas Program and the 1986 Energy Program were offered in
registered public offerings. The 1979 Program and 1986 Energy Program were offered privately to a limited number of sophisticated investors. 
  
 No drilling or income programs for third party investors were formed in 2004. Although it does not currently contemplate doing so, UNIT may form such
drilling or income programs during 2005. If such a program is formed, there would be only one or two such programs and they probably would be privately offered. The precise revenue and cost sharing format of any such programs has not been
determined. 
  
 The cost and revenue sharing provisions of
virtually all drilling programs offered to third parties generally require the limited partners or investors to bear a somewhat higher percentage of the program’s drilling and development costs than the percentage of program revenues to which
they are entitled. Likewise, the general partners will normally receive a higher percentage of revenues than the percentage of drilling and development costs which they are required to pay. The difference in these percentages is often referred to as
the general partners’ “promote.” Any drilling program which UNIT or UPC may form in 2005 for outside investors would likely have some amount of “promote” for the general partner(s). 
  
 Any income program may use the same or a similar format as that used for the
1986 Partnership. In the 1986 Partnership, virtually all partnership costs and expenses other than property acquisition costs are allocated to the partners in the same percentages that partnership revenue is being shared at the time such expenses
are incurred, with property acquisition costs and certain other expenses being charged 85% to the accounts of the limited partners and 15% to the accounts of the general partners. Partnership revenue in the 1986 Partnership is allocated 85% to the
limited partners’ accounts and 15% to the general partners’ accounts until program payout (as defined in the agreement of limited partnership for the 1986 Partnership). After program payout, the percentages of partnership revenue allocable
to the respective accounts of the partners depend upon the length of the period during which program payout occurs and range from 60% to the limited partners’ accounts and 40% to the general partners’ accounts to 85% to the limited
partners’ accounts and 15% to the general partners’ accounts. 
  
 As co-general partners of any drilling or income programs that may be formed by UNIT and/or UPC during 2005 and participated in by the Partnership, UNIT and/or UPC and the Partnership will share the costs, expenses and revenues allocable to
the general partners on a proportionate basis, 99% for the account of UNIT 

  

 21 

 
and/or UPC and 1% for the account of the Partnership. The Partnership will not receive any portion of any management fees payable to the general partners nor
any fees or payments for supervisory services which UNIT or UPC may render to such programs as operator of program wells or other fees and payments which UNIT or UPC may be entitled to receive from such programs for services rendered to them or
goods, materials, equipment or other property sold to them. 
  
 Extent and Nature of Operations. Although the General Partner maintains a general inventory of prospects, it cannot predict with certainty on which of those prospects wells will be started during 2005 nor can it predict what
producing properties, if any, will be acquired by it during 2005. Further, since the General Partner anticipates that the Partnership will acquire a small interest (either directly or through any drilling or income programs of which it or UNIT
serves as a general partner) in approximately 150 - 200 wells (however, the exact number of wells may vary greatly depending on the actual activity undertaken), it would be impractical to describe in any detail all of the properties in which the
Partnership can be expected to acquire some interest. 
  
 The
Partnership’s drilling and development operations are expected to include both Exploratory Wells and comparatively lower-risk Development Wells. Exploratory Wells include both the high-risk “wildcat” wells which are located in areas
substantially removed from existing production and “controlled” Exploratory Wells which are located in areas where production has been established and where objective horizons have produced from similar geological features in the vicinity.
Based on UNIT’s historical profile of its drilling operations, it is presently anticipated that the portion of the Aggregate Subscription expended for Partnership drilling operations (see “APPLICATION OF PROCEEDS”) will be spent
approximately 7% on Exploratory Wells and 93% on Development Wells. However, these percentages may vary significantly. 
  
 Certain of the Partnership’s Development Wells may be drilled on prospects on which initial drilling operations were conducted by the General Partner
or UNIT prior to the formation of the Partnership. Further, certain of the Partnership Wells will be drilled on prospects on which the General Partner, UNIT or possibly future employee programs may conduct additional drilling operations in years
subsequent to 2005. In either instance, the Partnership will have an interest only in those wells begun in 2005 and will have no rights in production from wells commenced in years other than 2005 even though such other wells may be located on
prospects or spacing units on which Partnership Wells have been drilled. Furthermore, it is possible that in years subsequent to 2005, UNIT, UPC or possibly future employee programs will acquire additional interests in wells participated in by the
Partnership. In such event the Partnership will generally not be entitled to share in the acquisition of such additional interests. With respect to the acquisition of producing properties, UNIT will endeavor to diversify its investments by acquiring
properties located in differing geographic locations and by balancing its investments between properties having high rates of production in early years and properties with more consistent production over a longer term. See “CONFLICTS OF
INTERESTS — Acquisition of Properties and Drilling Operations.” 
  
 Partnership Objectives 
  
 The Partnership
is being formed to provide eligible employees and directors the opportunity to participate in the oil and gas exploration and producing property acquisition activities of UNIT during 2005. UNIT hopes that participation in the Partnership will
provide the participants with greater proprietary interests in its operations and the potential for realizing a more direct benefit in the event these operations prove to be profitable. The Partnership has been structured to achieve the objective of
providing the Limited Partners with essentially the same economic returns that UNIT realizes from the wells drilled or acquired during 2005. 
  
 Areas of Interest 
  
 The Agreement authorizes the Partnership to engage in oil and gas exploration, drilling and development operations and to acquire producing oil and gas
properties anywhere in the United States, but the areas presently under consideration are located in the states of Oklahoma, Texas, Louisiana, Kansas, Arkansas, Colorado, Montana, North Dakota, New Mexico, Mississippi and Wyoming. It is possible
that the Partnership may drill in inland waterways, riverbeds, bayous or marshes but no drilling in the open seas will be attempted. Plans to conduct drilling and development operations or to acquire producing properties in certain of these states
may be abandoned if attractive prospects cannot be obtained upon satisfactory terms or if the Partnership is not fully subscribed. 
  

 22 

 Transfer of Properties 
  
 In the case of wells drilled or producing properties acquired by the Partnership and UPC or UNIT for their own accounts and
not through another drilling or income program, the Partnership will acquire from UPC or UNIT a portion of the fractional undivided working interest in the properties or portions thereof comprising the spacing unit on which a proposed Partnership
Well is to be drilled or on which a producing Partnership Well is located, and UPC or UNIT will retain for its own account all or a portion of the remainder of such working interest. Such working interests will be sold to the Partnership for an
amount equal to the Leasehold Acquisition Costs attributable to the interest being acquired. Neither UNIT nor its affiliates will retain any overrides or other burdens on the working interests conveyed to the Partnership, and the respective working
interests of UPC or UNIT and the Partnership in a property will bear their proportionate shares of costs and revenues. 
  
 The Partnership’s direct interest in a property will only encompass the area included within the spacing unit on which a Partnership Well is to be
drilled or on which a producing Partnership Well is located, and, in the case of a Partnership Well to be drilled, it will acquire that interest only when the drilling of the well is ready to commence. If the size of a spacing unit is ever reduced,
or any subsequent well in which the Partnership has no interest is drilled thereon, the Partnership will have no interest in any additional wells drilled on properties which were part of the original spacing unit unless such additional wells are
commenced during 2005. If additional interests in Partnership Wells are acquired in years subsequent to 2005 the Partnership will generally not be entitled to participate or share in the acquisition of such additional interests. In addition, if the
Partnership Well drilled on a spacing unit is dry or abandoned, the Partnership will not have an interest in any subsequent or additional well drilled on the spacing unit unless it is commenced during 2005. The Partnership will never own any
significant amounts of undeveloped properties or have an occasion to sell or farm out any undeveloped Partnership Properties. 
  
 Transfers of properties to any drilling or income programs of which the Partnership serves as a general partner will be governed by the provisions of the
agreement of limited partnership in effect with respect thereto. If any such program is to be offered publicly, those provisions will have to be consistent with the provisions contained in the Guidelines for the Registration of Oil and Gas Programs
adopted by the North American Securities Administrators Association, Inc. 
  
 Record Title to Partnership Properties 
  
 Record title to the Partnership Properties will be held by the General Partner. However, the General Partner will hold the Partnership Properties as a nominee for the Partnership under a form of nominee agreement to be entered into between
the General Partner and the Partnership. Under the form of nominee agreement, the General Partner will disclaim any beneficial interest in the Partnership Properties held as nominee for the Partnership. 
  
 Marketing of Reserves 
  
 The General Partner has the authority to market the oil and gas production
of the Partnership. In this connection, it may execute on behalf of the Partnership division orders, contracts for the marketing or sale of oil, gas or other hydrocarbons or other marketing agreements. Sales of the oil and gas production of the
Partnership will be to independent third parties or to the General Partner or its affiliates (see “CONFLICTS OF INTEREST”). 
  
 Conduct of Operations 
  
 The General Partner will have full, exclusive and complete discretion and control over the management, business and affairs of the Partnership and will
make all decisions affecting the Partnership Properties. To the extent that Partnership funds are reasonably available, the General Partner will cause the Partnership to (1) test and investigate the Partnership Properties by appropriate geological
and geophysical means, (2) conduct drilling and development operations on such Partnership Properties as it deems appropriate in view of such testing and investigation, (3) attempt completion of wells so drilled if in its opinion conditions warrant
the attempt and (4) properly equip and complete productive Partnership Wells. The General Partner will also cause the Partnership’s productive wells to be operated in accordance with sound and economical oil and gas recovery practices.

  
  

 23 

 The General Partner will operate certain drilling and productive wells on behalf of the Partnership in
accordance with the terms of the Agreement (see “COMPENSATION”). In those cases, execution of separate operating agreements will not be necessary unless third party owners are involved, e.g., fractional undivided interest Partnership
Properties and Partnership Properties that are pooled or unitized with other properties owned by third parties. In such cases, and in all cases where Partnership Properties are operated by third parties, the General Partner will, where appropriate,
make or cause to be made and enter into operating agreements, pooling agreements, unitization agreements, etc., in the form in general use in the area where the affected property is located. The General Partner is also authorized to execute
production sales contracts on behalf of the Partnership. 
  
 APPLICATION OF PROCEEDS 
  
 The Aggregate
Subscription will be used to pay costs and expenses incurred in the operations of the Partnership which are chargeable to the Limited Partners. The organizational costs of the Partnership and the offering costs of the Units will be paid by the
General Partner. 
  
 If all 600 Units offered hereby are sold, the
proceeds to the Partnership would be $600,000. If the minimum 50 Units are sold, the proceeds to the Partnership would be $50,000. The General Partner estimates that the gross proceeds will be expended as follows: 
  

													
	 	  	$600,000 Program

	  	$50,000 Program

	 	  	Percent

	 	 	Amount

	  	Percent

	 	 	Amount

	 Leasehold Acquisition Costs of Properties to Be Drilled
	  	5	%	 	$	30,000	  	5	%	 	$	2,500
	 Drilling Costs of Exploratory Wells
	  	5	%	 	 	30,000	  	5	%	 	 	2,500
	 Drilling Costs of Development Wells
	  	70	%	 	 	420,000	  	70	%	 	 	35,000
	 Leasehold Acquisition Costs of Productive Properties
	  	20	%	 	 	120,000	  	20	%	 	 	10,000
	 Total
	  	100	%	 	$	600,000	  	100	%	 	$	50,000

  
 The foregoing
allocation between Drilling Costs and Leasehold Acquisition Costs is solely an estimate and the actual percentages may vary materially from this estimate. Funds otherwise available for drilling Exploratory Wells will be reduced to the extent that
such funds are used in conducting development operations in which the Partnership participates. 
  
 Until Capital Contributions are invested in the Partnership’s operations, they will be temporarily deposited, with or without interest, in one or
more bank accounts of the Partnership or invested in short-term United States government securities, money market funds, bank certificates of deposit or commercial paper rated as “A1” or “P1” as the General Partner deems
advisable. Partnership funds other than Capital Contributions may be commingled with the funds of the General Partner or UNIT. 
  
 PARTICIPATION IN COSTS AND REVENUES 
  
 All costs of organizing the Partnership and offering Units therein will be paid by the General Partner. All costs incurred in the offering and syndication
of any drilling or income program formed by UPC or UNIT and its affiliates during 2005 in which the Partnership participates as a co-general partner will also be paid by the General Partner. All other Partnership costs and expenses will be charged
99% to the Limited Partners and 1% to the General Partner until such time as the Aggregate Subscription has been fully expended. Thereafter and until the General Partner’s Minimum Capital Contribution has been fully expended, all of such costs
and expenses will be charged to the General Partner. After the General Partner’s Minimum Capital Contribution has been fully expended, such costs and expenses will be charged to the respective accounts of the General Partner and the Limited
Partners on the basis of their respective Percentages (see “GLOSSARY”). 
  
  

 24 

 All Partnership Revenues will be allocated between the General Partner and the Limited Partners on the
basis of their respective Percentages. 
  
 The General
Partner’s Minimum Capital Contribution will be determined as of December 31, 2005 and will be an amount equal to: 
  

	 	(a)	all costs and expenses previously charged to the General Partner as of that date, plus 

  

	 	(b)	the General Partner’s good faith estimate of the additional amounts that it will have to contribute in order to fund the Leasehold Acquisition Costs and Drilling Costs expected
to be incurred by the Partnership after that date. 

  
 The
respective Percentages of the General Partner and the Limited Partners will then be determined as of December 31, 2005 based on the relative contributions of the Partners previously made and expected to be made in the future during the remainder of
the Partnership’s property acquisition and drilling phases. See “GLOSSARY — General Partner’s Minimum Capital Contribution”, “General Partner’s Percentage” and “ Limited Partners’ Percentage.”
If the General Partner’s estimate of future Leasehold Acquisition Costs and Drilling Costs proves to be lower than the actual amount of such costs and expenses, the excess amounts will be charged to the Partners on the basis of their respective
Percentages and the Limited Partners’ share will be paid out of their share of Partnership Revenues, Additional Assessments required of them or the proceeds of Partnership borrowings. See “ADDITIONAL FINANCING.” If the General
Partner’s estimate of such costs and expenses proves to be higher than the actual costs and expenses, the General Partner will continue to bear Partnership costs and expenses that would otherwise have been chargeable to the Limited Partners
until the total Partnership costs and expenses charged to it (including, without limitation, offering and organizational costs, Operating Expenses, general and administrative overhead costs and reimbursements and Special Production and Marketing
Costs as well as Leasehold Acquisition Costs and Drilling Costs) since the formation of the Partnership equals the General Partner’s Minimum Capital Contribution. In addition to actual contributions of cash or properties, any Partner will be
deemed to have contributed amounts of Partnership Revenues allocated to it which are used to pay its share of Partnership costs and expenses. 
  

 25 

 The following table presents a summary of the allocation of Partnership costs, expenses and revenues
between the General Partner and the Limited Partners: 
  

					
	 	  	 General Partner

	    	Limited Partners

	 COSTS AND EXPENSES
	  	 	    	 
			
	 •      Organizational and offering costs of the Partnership and any drilling or income programs in which
the Partnership participates as a co-general partner
	  	100%	    	0%
			
	 •      All other Partnership Costs and Expenses:
	  	 	    	 
			
	 •      Prior to time Limited Partner Capital Contributions are Entirely expended
	  	1%	    	99%
			
	 •      After expenditure of Limited Partner Capital Contributions and until expenditure of General
Partner’s Minimum Capital Contribution
	  	100%	    	0%
			
	 •      After expenditure of General Partner’s Minimum Capital Contribution
	  	General Partner’s Percentage	    	Limited Partners’
Percentage
			
	 REVENUES
	  	General Partner’s Percentage	    	Limited Partners’
Percentage

  
 COMPENSATION

  
 Supervision of Operations 
  
 It is anticipated that the General Partner will operate most, if not all,
Partnership Properties during the drilling of Partnership Wells and most, if not all, productive Partnership Wells. For the General Partner’s services performed as operator, the Partnership will compensate the General Partner its pro rata
portion of the compensation due to the General Partner under the operating agreements, if any, in effect with respect to such wells or, if none is in effect for such wells, at rates no higher than those normally charged in the same or a comparable
geographic area by non-affiliated persons or companies dealing at arm’s length. 
  
 That portion of the General Partner’s general and administrative overhead expense that is attributable to its conduct of the actual and necessary business, affairs and operations of the Partnership will be
reimbursed by the Partnership out of Partnership Revenue. The General Partner’s general and administrative overhead expenses are determined in accordance with industry practices. The costs and expenses to be allocated include all customary and
routine legal, accounting, geological, engineering, travel, office rent, telephone, secretarial, salaries, data processing, word processing and other incidental reasonable expenses necessary to the conduct of the Partnership’s business and
generated by the General Partner or allocated to it by UNIT, but will not include filing fees, commissions, professional fees, printing costs and other expenses incurred in forming the Partnership or offering interests therein. The amount of such
costs and expenses to be reimbursed with respect to any particular period will be determined by allocating to the Partnership that portion of the General Partner’s total general and administrative overhead expense incurred during such period
which is equal to the ratio of the Partnership’s total expenditures compared to the total expenditures by the General Partner for its own account. The portion of such general and administrative overhead expense reimbursement which is charged to
the Limited 
  

 26 

 Partners may not exceed an amount equal to 3% of the Aggregate Subscription during the first 12 months of the
Partnership’s operations, and in each succeeding twelve-month period, the lesser of (a) 2% of the Aggregate Subscription and (b) 10% of the total Partnership Revenue realized in such twelve-month period. Administrative expenses incurred
directly by the Partnership, or incurred by the General Partner on behalf of the Partnership and reimbursable to the General Partner, such as legal, accounting, auditing, reporting, engineering, mailing and other such fees, costs and expenses are
not considered a part of the general and administrative expense reimbursed to the General Partner and the amounts thereof will not be subject to the limitations described in the preceding sentence. 
  
 Purchase of Equipment and Provision of Services 
  
 UNIT, through its subsidiary Unit Drilling Company, will probably perform
significant drilling services for the Partnership. UNIT also owns Superior Pipeline Company, L.L.C., an Oklahoma limited liability company, which may build or own an interest in certain gathering systems through which a portion of the
Partnership’s gas production is transported. 
  
 These
persons are in the business of supplying such equipment and services to non-affiliated parties in the industry and any such equipment and such services will be acquired or provided at prices or rates no higher than those normally charged in the same
or comparable geographic area by non-affiliated persons or companies dealing at arms’ length. Production purchased by any affiliate of UNIT will be for prices which are not less than the highest posted price (in the case of crude oil) or
prevailing price (in the case of natural gas) in the same field or area. 
  
 UNIT or one of its affiliates may provide other goods or services to the Partnership in which event the compensation received therefore will be subject to the same restrictions and conditions described above and under
“CONFLICTS OF INTEREST” below. 
  
 Prior Programs

  
 UNIT was formed in 1986 in connection with a major
reorganization and recapitalization whereby UNIT acquired all of the assets and liabilities of all of the limited partnerships formed by UNIT’s predecessor, Unit Drilling and Exploration Company (“UDEC”), during the period of
1980 through 1983 in exchange for shares of UNIT’s common stock and UDEC was merged with a wholly owned subsidiary of UNIT whereby UDEC was the surviving corporation and thereby became a wholly owned subsidiary of UNIT. UNIT has conducted one
oil and gas program since the date of its formation, the 1986 Energy Program. The 1986 Energy Program was formed on June 12, 1987 with total subscriptions of one million dollars. The Unit 1986 Employee Oil and Gas Limited Partnership is a co-general
partner with Unit Petroleum Company of the 1986 Energy Program. Direct compensation charged to or paid by the partnerships and earned by the General Partners for their services in connection with these programs through September 30, 2004, is set
forth below. 
  
  

 27 

										
	 Program

	  	Management
Fee(1)

	 	 	Compensation for
Supervision and
Operation of
Productive and
Drilling Wells(2)(3)

	  	Reimbursement
of General
Administrative
and Overhead
Expense(2)(3)(4)

	  	 Fees
Received as
 a Drilling
Contractor(2)

	 1979(***)
	  	150,000	 	 	2,833,720	  	2,539,915	  	1,835,762
	 1980
	  	200,000	 	 	261,456	  	1,345,158	  	1,810,310
	 1981
	  	1,250,000	(5)	 	329,695	  	1,892,568	  	4,047,260
	 1981-II
	  	450,000	 	 	158,406	  	1,607,706	  	1,629,201
	 1982-A
	  	634,200	 	 	521,910	  	1,688,024	  	4,110,107
	 1982-B
	  	316,650	 	 	331,594	  	1,224,023	  	4,945,437
	 1983-A
	  	50,600	 	 	151,289	  	698,597	  	695,255
	 1984
	  	—  	 	 	313,310	  	1,036,106	  	829,503
	 1984 Employee(*)
	  	—  	 	 	3,924	  	5,000	  	13,452
	 1985 Employee(*)
	  	—  	 	 	10,316	  	—  	  	54,892
	 1986 Energy Income Fund(**)
	  	—  	 	 	371,456	  	1,371,353	  	64,945
	 1986 Employee(*)
	  	—  	 	 	23,505	  	—  	  	59,446
	 1987 Employee(*)
	  	—  	 	 	50,688	  	—  	  	97,079
	 1988 Employee(*)
	  	—  	 	 	93,854	  	—  	  	112,861
	 1989 Employee(*)
	  	—  	 	 	54,536	  	—  	  	165,436
	 1990 Employee(*)
	  	—  	 	 	28,884	  	—  	  	144,722
	 1991 Employee(****)
	  	—  	 	 	572,357	  	—  	  	144,993
	 1992 Employee(****)
	  	—  	 	 	159,914	  	—  	  	14,934
	 1993 Employee(****)
	  	—  	 	 	85,790	  	—  	  	68,504
	 1994 Employee(****)
	  	—  	 	 	122,392	  	—  	  	42,135
	 1995 Employee(****)
	  	—  	 	 	72,331	  	—  	  	35,903
	 1996 Employee(****)
	  	—  	 	 	85,199	  	—  	  	112,911
	 1997 Employee(****)
	  	—  	 	 	75,475	  	—  	  	170,174
	 1998 Employee(****)
	  	—  	 	 	57,689	  	—  	  	161,343
	 1999 Employee(****)
	  	—  	 	 	95,782	  	—  	  	186,408
	 Consolidated Program(*)(****)
	  	—  	 	 	279,288	  	—  	  	734
	 2000 Employee
	  	—  	 	 	78,525	  	—  	  	600,771
	 2001 Employee
	  	—  	 	 	22,371	  	—  	  	360,950
	 2002 Employee
	  	—  	 	 	15,235	  	—  	  	273,603
	 2003 Employee
	  	—  	 	 	10,960	  	—  	  	446,564
	 2004 Employee
	  	—  	 	 	684	  	—  	  	419,357

	(*)	Effective December 31, 1993, pursuant to an Agreement and Plan of Merger, this employee partnership was merged with and into the Unit Consolidated Employee Oil and
Gas Limited Partnership (the “Consolidated Program”), with the latter being the surviving limited partnership. See Prior Activities. 

	(**)	Formed primarily for purposes of acquiring producing oil and gas properties. 

	(***)	Effective July 1, 2003 this program was dissolved. 

	(****)	Effective December 31, 2002, pursuant to an Agreement and Plan of Merger, this employee partnership was merged with and into the Unit Consolidated Employee Oil and
Gas Limited Partnership (the “Consolidated Program”), with the latter being the surviving limited partnership. See Prior Activities. 

	(1)	Paid to both UDEC and a prior Key Employee Exploration Fund as general partners. No management fee was payable to UDEC or any of its affiliates by any of the 1984 - 2004 Employee
Programs and no management fee is payable by the Partnership to UNIT or any of its affiliates. 

  

 28 

	(2)	Paid only to UDEC. 

	(3)	In the case of compensation for supervision and operation of productive wells and reimbursement of UNIT’s general and administrative overhead expense, the general partners
generally were charged with and paid a percentage of such amounts equal to the percentage of partnership revenues being allocated to them. 

	(4)	Although the partnership agreement for each of the 1985 - 2004 Employee Programs provides that the General Partner is entitled to reimbursement for the general administrative and
overhead expenses attributable to each of such programs, the General Partner has to date elected not to seek such reimbursement. However, there can be no assurance that the General Partner will continue to forego such reimbursement in the future.

	(5)	Includes a special allocation of gross revenues totaling $500,000. 

  
 MANAGEMENT 
  
 The General Partner 
  
 UNIT was formed in 1986 in connection with a major reorganization and recapitalization whereby UNIT acquired all of the assets and liabilities of all of
the limited partnerships formed by UNIT’s predecessor, UDEC, in exchange for shares of UNIT’s common stock in a transaction whereby UDEC became a wholly owned subsidiary of UNIT. UPC was incorporated in the State of Oklahoma on February 9,
1984 as Sunshine Development Corporation (“SDC”) and was acquired by UDEC in 1985. The name was changed to Unit Petroleum Company in 1988. On October 8, 1985 pursuant to the terms of a Stock Purchase Agreement,” UDEC purchased
all of the issued and outstanding stock of SDC whereby SDC became a wholly owned subsidiary of UDEC. On February 1, 1988, pursuant to the terms of an “Amended and Restated Certificate of Incorporation”, SDC was renamed Unit Petroleum
Company. 
  
 UPC’s as well as UNIT’s, principal office
is at 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136 and its telephone number is (918) 493-7700. UNIT through its various subsidiaries is engaged in the onshore contract drilling of oil and gas wells, the exploration for and production of oil
and gas and the gathering and transportation of natural gas. Unless the context otherwise requires, references in this Memorandum to UNIT include its predecessor as well as all or any of its subsidiaries. 
  
 Officers, Directors and Key Employees 
  
 The Partnership will have no directors or officers. The directors of the
General Partner are elected annually and serve until their successors are elected and qualified. Directors of UNIT are elected at the Annual Meeting of Shareholders for a staggered term of three years each, or until their successors are duly elected
and qualified. The executive officers of the General Partner are elected by and serve at the pleasure of its Board of Directors. The names, ages and respective positions of the directors and executive officers of UNIT are as follows: 
  

					
	 Name

	  	Age

	    	 Position

	 King P. Kirchner
	  	77	    	 Director

			
	 John G. Nikkel*
	  	69	    	 Chairman of the Board, Chief Executive Officer and Director

			
	 Larry D. Pinkston*
	  	50	    	 President, Chief Operating Officer and Director

			
	 Mark E. Schell
	  	47	    	 Senior Vice President, Secretary and General Counsel

			
	 David T. Merrill
	  	43	    	 Treasurer and Chief Financial Officer

			
	 William B. Morgan
	  	60	    	 Director

  

 29 

					
	 Name

	  	Age

	    	 Position

	 Don Cook
	  	79	    	 Director

			
	 John S. Zink
	  	76	    	 Director

			
	 John H. Williams
	  	86	    	 Director

			
	 J. Michael Adcock
	  	55	    	 Director

			
	 Mark E. Monroe
	  	50	    	 Director

	*	Mr. Nikkel has announced his intention to resign as the Chief Executive Officer of the Company effective April 1, 2005. The Company’s Board of Directors has elected Mr.
Pinkston to succeed Mr. Nikkel as the Company Chief Executive Officer. 

  
 The names, ages and respective positions of the directors and executive officers of UPC are as follows: 
  

					
	 Name

	  	Age

	    	 Position

	 John G. Nikkel
	  	69	    	 Chairman of the Board and Director

			
	 Larry D. Pinkston
	  	50	    	 President and Director

			
	 Mark E. Schell
	  	47	    	 Senior Vice President, Secretary and General Counsel

  
 Mr. Kirchner, a
co-founder of UNIT, has been a director since 1963. He served as the Company’s President until November, 1983, as its Chief Executive Officer until June 30, 2001, and served as the Chairman of the Board until July 31, 2003. Mr. Kirchner is a
Registered Professional Engineer within the State of Oklahoma, having received degrees in Mechanical Engineering from Oklahoma State University and in Petroleum Engineering, with honors, from the University of Oklahoma. Following graduation, he was
employed by Lufkin Manufacturing as a development engineer for hydraulic pumping units. Prior to co-founding Unit, he served in the U.S. Army during the Korean War and after that as vice-president engineering and operations for Woolaroc Oil Company.

  
 Mr. Nikkel joined Unit as its President, Chief Operating
Officer and a director in 1983. He was elected its Chief Executive Officer in July, 2001 and Chairman of the Board in August, 2003. He currently holds the position of Chairman of the Board and Chief Executive Officer. From 1976 until January, 1982
when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and director of Cotton Petroleum Corporation, serving as the President of Cotton from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco
Production Company for 18 years, last serving as Division Geologist for Amoco’s Denver Division. Mr. Nikkel presently serves as President and a director of Nike Exploration Company. From August 16, 2000 until August 23, 2002 Mr. Nikkel, in
connection with Unit’s investment in the company, also served as a director of Shenandoah Resources Ltd., a Canadian company. Shenandoah Resources Ltd. filed for creditors protection under The Companies’ Creditor Arrangement Act in April
2002 with the Court of Queen’s Bench of Alberta, Judicial District of Calgary. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University. 
  
 Mr. Pinkston joined UNIT in December, 1981. He had served as Corporate Budget
Director and Assistant Controller prior to being appointed Controller in February, 1985. In December, 1986 he was elected Treasurer of the company and was elected to the position of Vice President and Chief Financial Officer in May, 1989. In August,
2003, he was elected to the position of President of the company as well as serving as its Chief Financial Officer. He was elected a director of the company by the Board in January, 2004. In February, 2004, in addition to his position as President,
he was elected to the office of Chief Operating Officer. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma and is a Certified Public Accountant. 
  

 30 

 Mr. Schell joined UNIT in January, 1987, as its Secretary and General Counsel. In December, 2002, he was
elected to the additional position of Senior Vice President. From 1979 until joining UNIT, Mr. Schell was Counsel, Vice President and a member of the Board of Directors of C&S Exploration, Inc. He received a Bachelor of Science degree in
Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa Law School. He is a member of the Oklahoma and American Bar Association as well as being a member of the American Corporate Counsel
Association and the American Society of Corporate Secretaries. 
  
 Mr. Merrill joined Unit in August, 2003 as Vice President, Finance. From May, 1999 through August, 2003, Mr. Merrill served as Senior Vice President, Finance with TV Guide Networks, Inc. From July, 1996 through May, 1999 he was a Senior
Manager with Deloitte & Touche LLP. From July, 1994 through July, 1996 he was Director of Financial Reporting and Special Projects for MAPCO, Inc. He began his career as an auditor with Deloitte, Haskins & Sells in 1983. Mr. Merrill received
a Bachelor of Business Administration Degree in Accounting from the University of Oklahoma and is a Certified Public Accountant. In February, 2004 he was elected to the position of Treasurer and Chief Financial Officer. 
  
 Mr. Morgan was elected a director of UNIT in February, 1988. For over 5
years, Mr. Morgan has been Executive Vice President and General Counsel of St. John Health System, Inc., Tulsa, Oklahoma, and the President of its principal for-profit subsidiary Utica Services, Inc. Before that, he was a Partner in the law firm of
Doerner, Saunders, Daniel & Anderson, Tulsa, Oklahoma, for over 20 years. 
  
 Mr. Cook has served as a director of Unit since Unit’s inception. He is a Certified Public Accountant and was a partner in the accounting firm of Finley & Cook, Shawnee, Oklahoma, from 1950 until 1987, when
he retired. Mr. Cook has been designated by the company’s board of directors as the Audit Committee’s financial expert. 
  
 Mr. Zink was elected a director of UNIT in May, 1982. For over 5 years, he has been a principal in several privately held companies engaged in the
businesses of designing and manufacturing equipment used in the petroleum industry, construction, and heating and air conditioning services and installation. He holds a Bachelor of Science degree in Mechanical Engineering from Oklahoma State
University. He is also a director of Matrix Service Company, Tulsa, Oklahoma. 
  
 Mr. Williams was elected a director of UNIT in December, 1988. Prior to retiring on December 31, 1978, he was Chairman of the Board and Chief Executive Officer of The Williams Companies, Inc., where he continues to
serve as an honorary director. Mr. Williams also serves as a director of Apco Argentina, Inc., Petrolera Perez Companc S.A., and Willbros Group, Inc. In addition, Mr. Williams is a member of the Tulsa Performing Arts Center Trust. 
  
 Mr. Adcock was elected a director of UNIT in December, 1997. He is an
attorney and currently manages a private trust that deals in real estate, oil and gas properties and other equity investments. He is Chairman of the Board of Arvest Bank, Shawnee, and a director of Community Health Partners, Inc., formerly Mid
America Healthcare, Inc. Between 1997 and September, 1998 he was the Chairman of the Board of Ameribank and President and Chief Executive Officer of American National Bank and Trust Company of Shawnee, Oklahoma, and Chairman of AmeriTrust
Corporation, Tulsa, Oklahoma. Prior to holding these positions, he was engaged in the private practice of law and served as General Counsel for Ameribank Corporation. 
  
 Mr. Monroe was the Chief Executive Officer and President of Louis Dreyfus Natural Gas Corp., a publicly-held natural gas
exploration and production company, until the sale of the company in 2001. Prior to the formation of Louis Dreyfus Natural Gas in 1990, Mr. Monroe was the Chief Financial Officer of Bogert Oil Company, a publicly-held exploration and production
company headquartered in Oklahoma City, Oklahoma. From 1976 to 1980, he was an Audit Manager for the public accounting firm of Deloitte & Touche in Dallas, Texas. Mr. Monroe currently serves as a member of the Board of Directors for Continental
Resources, Inc., a privately-held exploration and production company headquartered in Enid, Oklahoma and on the board of the Oklahoma Independent Petroleum Association, of which he previously served as its President. He has served on the Domestic
Petroleum Council, on the National Petroleum Council and on the Boards of the Independent Petroleum Association of America and the Petroleum Club of Oklahoma City. Mr. Monroe graduated from the University of Texas at Austin with a BBA degree in 1975
and is a Certified Public Accountant. 
  

 31 

 Prior Employee Programs 
  
 Since 1984, UNIT has formed limited partnerships for investment by certain of its key employees and directors that
participate with UNIT in its exploration and production operations. The name, month of formation and amount of limited partner capital subscriptions of each of these limited partnerships (the “Employee Programs”) are set forth
below. 
  

						
	 Name

	  	 Formed

	  	Limited
Partners’
Capital
Subscriptions

	 Unit 1984 Employee Oil and Gas Program
	  	April 1984	  	$	348,000
	 Unit 1985 Employee Oil and Gas Limited Partnership
	  	January 1985	  	$	378,000
	 Unit 1986 Employee Oil and Gas Limited Partnership
	  	January 1986	  	$	307,000
	 Unit 1987 Employee Oil and Gas Limited Partnership
	  	March 1987	  	$	209,000
	 Unit 1988 Employee Oil and Gas Limited Partnership
	  	April 29, 1988	  	$	177,000
	 Unit 1989 Employee Oil and Gas Limited Partnership
	  	December 30, 1988	  	$	157,000
	 Unit 1990 Employee Oil and Gas Limited Partnership
	  	January 19, 1990	  	$	253,000
	 Unit 1991 Employee Oil and Gas Limited Partnership
	  	January 7, 1991	  	$	263,000
	 Unit 1992 Employee Oil and Gas Limited Partnership
	  	January 23, 1992	  	$	240,000
	 Unit 1993 Employee Oil and Gas Limited Partnership
	  	January 21, 1993	  	$	245,000
	 Unit 1994 Employee Oil and Gas Limited Partnership
	  	January 19, 1994	  	$	284,000
	 Unit 1995 Employee Oil and Gas Limited Partnership
	  	March 7, 1995	  	$	454,000
	 Unit 1996 Employee Oil and Gas Limited Partnership
	  	February 5, 1996	  	$	437,000
	 Unit 1997 Employee Oil and Gas Limited Partnership
	  	February 4, 1997	  	$	413,000
	 Unit 1998 Employee Oil and Gas Limited Partnership
	  	February 19, 1998	  	$	471,000
	 Unit 1999 Employee Oil and Gas Limited Partnership
	  	February 22, 1999	  	$	188,000
	 Unit 2000 Employee Oil and Gas Limited Partnership
	  	February 22, 2000	  	$	199,000
	 Unit 2001 Employee Oil and Gas Limited Partnership
	  	February 9, 2001	  	$	370,000
	 Unit 2002 Employee Oil and Gas Limited Partnership
	  	January 30, 2002	  	$	457,000
	 Unit 2003 Employee Oil and Gas Limited Partnership
	  	January 31, 2003	  	$	284,000
	 Unit 2004 Employee Oil and Gas Limited Partnership
	  	February 18, 2004	  	$	434,000

  

 32 

 One-half of the capital subscriptions from all limited partners were required to be paid in the 1984
Employee Program, three-fourths of the capital subscriptions from all limited partners were required to be paid in the 1985 Employee Program and the 1986 Employee Program. All of the capital subscriptions from all limited partners, including those
shown below, were required to be paid in the 1987 through 2004 Employee Programs. The capital subscriptions of the following limited partners to the 2002, 2003 and 2004 Employee Programs were as shown below: 
  

										
	 Subscriber

	  	 Position with UNIT

	  	 Amount of Capital
 Subscription

	  	  	2002

	  	2003

	  	2004

	 King P. Kirchner(1)
	  	 Director
	  	100,000	  	40,000	  	$	40,000
	 John G. Nikkel(2)
	  	 Chairman, Chief Executive Officer and Director
	  	200,000	  	140,000	  	$	200,000

	(1)	Mr. Kirchner invested $100,000 in the 2002 Employee Program, $40,000 in the 2003 Employee Program and $40,000 in the 2004 Employee Program, through the King P. Kirchner Revocable
Trust as permitted by the limited partnership agreement of those Employee Programs. 

	(2)	Mr. Nikkel invested in the 2002, 2003 and 2004 Employee Programs both directly and through Nike Exploration Company. Mr. Nikkel and members of his family are the sole owners of Nike
Exploration Company. The amounts invested directly and indirectly through Nike Exploration Company in the 2002, 2003 and 2004 Employee Programs by Mr. Nikkel were as follows: 

  

							
	 Employee
 Program

	 	Mr. Nikkel
Directly

	 	Nike Exploration
Company

	2002	 	$	100,000	 	$	100,000
	2003	 	$	80,000	 	$	60,000
	2004	 	$	100,000	 	 	100,000

  
 Ownership of Common Stock

  
 UNIT’s Common Stock is listed on the New York
Stock Exchange as reported on the Composite Tape. On December 9, 2004 there were 45,739,599 shares outstanding. 
  
 As of December 9, 2004, the directors and officers of UNIT owned of record or beneficially owned shares of UNIT Common Stock as follows: 
  

							
	 Name

	  	Amount of
Beneficial
Ownership(1)

	 	 	% of
Outstanding(1)

	 
	 King P. Kirchner
	  	165,320	 	 	*	 
	 John H. Williams
	  	15,000	 	 	*	 
	 Don Cook
	  	33,118	 	 	*	 
	 John G. Nikkel
	  	397,267	 	 	*	 
	 Larry D. Pinkston
	  	74,608	 	 	*	 
	 Mark E. Schell
	  	74,209	 	 	*	 
	 John S. Zink
	  	12,600	 	 	*	 
	 William B. Morgan
	  	24,000	 	 	*	 
	 J. Michael Adcock
	  	122,191	 	 	*	 
	 Mark E. Monroe
	  	6,500	 	 	*	 
	 David T. Merrill
	  	1,600	 	 	*	 
	 All Officers and Directors as a Group
	  	926,413	(2)(3)(4)(5)	 	2.0	%

	*	Less than 1% 

  

 33 

	(1)	The number of shares includes the shares presently issued and outstanding plus the number of shares which any owner has the right to acquire within 60 days after December 9, 2004,
pursuant to the exercise of currently exercisable stock options. For purposes of calculating the percent of the shares outstanding held by each owner, the total number of shares excludes the shares which all other persons have the right to acquire
within 60 days after December 9, 2004 pursuant to the exercise of currently exercisable stock options. 

	(2)	Includes shares of common stock held under UNIT’s 401(k) thrift plan as of December 9, 2004 for the account of: John G. Nikkel, 32,787; David T. Merrill, 40; Larry D. Pinkston,
3,933; and Mark E. Schell, 31,573. 

	(3)	Includes unexercised stock options granted under UNIT’s Non-Employee Directors’ Stock Option Plan to each of the following, all of which are currently exercisable at the
discretion of the holder: J. Michael Adcock, 14,000; Don Cook, 22,500; Mark E. Monroe, 3,500; William B. Morgan, 19,000; John H. Williams, 14,000; John S. Zink, 10,500; and King P. Kirchner 10,500 shares and all Non-Employee Directors as a group,
94,000. 

	(4)	Includes unexercised stock options granted under UNIT’s Amended and Restated Stock Option Plan to each of the following, all of which are exercisable within 60 days from
December 9, 2004 at the discretion of the holder: John G. Nikkel 29,000; David T. Merrill, 1,600; Larry D. Pinkston, 30,500; and Mark E. Schell, 30,000. 

	(5)	Of the shares shown, Mr. J. Michael Adcock is deemed to be the beneficial owner of 107,491 shares by virtue of his position as one of three trustees of the Don Bodard 1995 Revocable
Trust. 

  
 Interest of Management in Certain Transactions

  
 Reference is made to “COMPENSATION” for a
discussion of the compensation for supervision and operation of productive wells and the reimbursement of overhead expenses attributable to the Partnership’s operations to which UNIT is entitled under the terms of the Partnership Agreement.

  
 CONFLICTS OF INTEREST 
  
 There will be situations in which the individual interests of the General
Partner and the Limited Partners will conflict. Although the General Partner is obligated to deal fairly and in good faith with the Limited Partners and conduct Partnership operations using the standards of a prudent operator in the oil and gas
industry, such conflicts may not in every instance be resolved to the maximum advantage of the Limited Partners. Certain circumstances which will or may involve potential conflicts of interest are as follows: 
  

	 	•	 	The General Partner currently manages and in the future will sponsor and manage oil and natural gas drilling programs similar to the Partnership. 

  

	 	•	 	The General Partner will decide which prospects the Partnership will acquire. 

  

	 	•	 	The General Partner will act as operator for Partnership Wells and will, through its affiliates, furnish drilling and/or marketing services with respect to Partnership Wells, the
terms of which have not been negotiated by non-affiliated persons. 

  

	 	•	 	The General Partner is a general partner of numerous other partnerships, and owes duties of good faith dealing to such other partnerships. 

  

	 	•	 	The General Partner and its affiliates engage in drilling, operating and producing activities for other partnerships. 

  
 Acquisition of Properties and Drilling Operations 
  
 With certain limited exceptions it is anticipated that the Partnership will
participate in each producing property, if any, acquired by the General Partner and in the drilling of each of the wells, if any, commenced by the 

  

 34 

 
General Partner for its own account during the period commencing January 1, 2005, or from the formation of the Partnership if subsequent to January 1, 2005,
through December 31, 2005 except for wells: 
  

	 	(i)	drilled outside the 48 contiguous United States; 

  

	 	(ii)	drilled as part of secondary or tertiary recovery operations which were in existence prior to formation of the Partnership; 

  

	 	(iii)	drilled by third parties under farm-out or similar arrangements with UNIT or the General Partner or whereby UNIT or the General Partner may be entitled to an overriding royalty,
reversionary or other similar interest in the production from such wells but is not obligated to pay any of the Drilling Costs thereof; 

  

	 	(iv)	acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies; or

  

	 	(v)	with respect to which the General Partner does not believe that the potential economic return therefrom justifies the costs and participation by the Partnership.

  
 As a result, the Partnership may have an interest in wells
located on prospects on which producing wells have been drilled by UNIT or the General Partner in prior years. Likewise, it is possible that the Partnership will participate in the drilling of initial wells on prospects on which some or all of the
development or offset wells will be drilled in years subsequent to 2005. In the latter case, the Partnership would have no right to participate in the drilling of such development or offset wells. 
  
 Sometimes UNIT will agree to participate in drilling operations on a prospect
which it may not believe are fully warranted from an economic standpoint if it believes that such participation is necessary for, or will significantly increase its chances of, obtaining a contract to drill the well with one of its drilling rigs and
the revenues from the contract make the economics of the entire arrangement desirable from UNIT’s standpoint. In such an instance, the Partnership would not be entitled to any of the drilling contract revenues so the General Partner will not
cause the Partnership to participate in such a well. However, an analysis of the economic potential of any proposed well is a very inexact science and wells which have a very high potential commonly prove to be dry or only marginally profitable and
occasionally a well with apparently very little promise may prove to be very profitable. Thus, there can be no assurance that the General Partner will always make the most profitable decision from the Partnership’s standpoint in determining in
which of such potential wells the Partnership should or should not participate. 
  
 Because the Partnership will acquire an interest only in those properties comprising the spacing unit on which each Partnership Well is located, it will not be entitled to participate in other wells drilled by the
General Partner, UNIT or any of its affiliates in the same prospect area unless the drilling of those wells commences during the period from January 1, 2005, or from the formation of the Partnership if subsequent to January 1, 2005, through December
31, 2005. If the size of a spacing unit in which the Partnership has an interest is reduced, the Partnership will have no interest in any additional well drilled on the property comprising the original spacing unit unless it is commenced during the
period from January 1, 2005, or from the formation of the Partnership if subsequent to January 1, 2005, through December 31, 2005. Likewise the Partnership would have no interest in any increased density wells drilled on the original spacing unit
unless such wells were drilled during 2005. In addition, if additional interests are acquired in wells participated in by the Partnership after 2005, the Partnership will generally not be entitled to participate in the acquisition of such additional
interests. Management believes that the apparent conflicts of interest arising from these situations are mitigated by the fact that the Partnership is expected to participate in all of UNIT’s drilling operations (with the exceptions noted
above) conducted during the period. Thus, there is little opportunity for the General Partner to selectively choose Partnership drilling locations for the purpose of proving up other properties of UNIT or its affiliates in which the Partnership has
no interest. Further, the Partnership will benefit in many instances by its participation in the drilling of wells located on prospects previously proved up by drilling operations conducted by UNIT prior to formation of the Partnership. 

 

 35 

 Participation in UNIT’s Drilling or Income Programs 
  
 If UNIT forms any drilling or income programs in 2005, it is anticipated
that the Partnership will serve as a co-general partner with UNIT in any such drilling or income programs, or both. As the other co-general partner of any such drilling or income program, UNIT would have exclusive management and control over the
business, operations and affairs of the drilling or income program. Conflicts of interest may arise between the limited partners and the general partners of such drilling or income program and it is possible that UNIT may elect to resolve those
conflicts in favor of the limited partners. Further, if any such drilling or income program is offered publicly, the program agreement will be required to contain a number of provisions concerning the conduct of program operations and handling
conflicts of interests required by the Guidelines for the Registration of Oil and Gas Programs adopted by the North American Securities Administrators Association, Inc. Such provisions may significantly reduce the flexibility of UNIT in managing
such programs or may affect the profitability of the program operations or the transactions between the general partners and the program. 
  
 Transfer of Properties 
  
 The General Partner or its affiliates are authorized to transfer interests in oil and gas properties to the Partnership, in which case the General Partner
or its affiliate will receive an amount equal to the Leasehold Acquisition Costs attributable to the interests being acquired by the Partnership in the spacing unit on which the Partnership Well is located or is to be drilled. The amount of the
Leasehold Acquisition Costs attributable to the fractional undivided interest in a property transferred to the Partnership by the General Partner or any affiliate shall not be reduced or offset by the amount of any gain or profit the General Partner
or its affiliate might have realized by any prior sale or transfer of a fractional undivided interest in the property to an unaffiliated third party for a price in excess of the portion of the Leasehold Acquisition Costs of the property that is
attributable to the transferred interest. The Partnership will not be reimbursed for or refunded any Leasehold Acquisition Costs if the size of a spacing unit on which a Partnership Well is located or drilled is reduced even though the Partnership
will have no interest in any subsequent wells drilled on the area encompassed by the original spacing unit unless they are commenced during 2005. 
  
 A sale, transfer or conveyance to the Partnership of less than all of the ownership of the General Partner or its affiliates in any interest or property
is prohibited unless: 
  

	 	(1)	the interest retained by the General Partner or its affiliates is a proportionate working interest; 

  

	 	(2)	the obligations of the Partnership with respect to the properties will be substantially the same proportionately as those of the General Partner or its affiliates at the time it
acquired the properties; and 

  

	 	(3)	the Partnership’s interest in revenues will not be less than the proportionate interest therein of the General Partner or its affiliates when it acquired the properties.

  
 With respect to the General Partner or its affiliates’
remaining interest, it may retain such interest for its own account or it may sell, transfer, farm-out or otherwise convey all or a portion of such remaining interest to non-affiliated industry members, which may occur either before or after the
transfer of the interests in the same properties to the Partnership. The General Partner or its affiliates may realize a profit on the interests or may be carried to some extent with respect to its cost obligations in connection with any drilling on
such properties and any such profit or interests will be strictly for the account of the General Partner or its affiliates and the Partnership will have no claim with respect thereto. The General Partner or its affiliates may not retain any
overrides or other burdens on the property conveyed to the Partnership (other than overriding royalty interests granted to geologists and other persons employed or retained by the General Partner or its affiliates) and may not enter into any
farm-out arrangements with respect to its retained interest except to non-affiliated third parties or other programs managed by the General Partner or its affiliates. 
  
 Partnership Assets 
  
 The General Partner will not take any action with respect to assets or property of the Partnership which does not benefit primarily the Partnership as a
whole. The General Partner will not utilize the funds of the 

  

 36 

 
Partnership as compensating balances for the benefit of the General Partner or its affiliates. All benefits from marketing arrangements or other
relationships affecting property of the Partnership will be fairly and equitably apportioned according to the respective interests of the Partnership and the General Partner. 
  
 The Partnership Agreement provides that when the Partnership is terminated, there will be an accounting with respect to its
assets, liabilities and accounts. The Partnership’s physical property and its oil and gas properties may be sold for cash. Except in the case of an election by the General Partner to terminate the Partnership before the tenth anniversary of the
Effective Date, Partnership Properties may be sold to the General Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner. 
  
 Transactions with the General Partner or Affiliates 
  
 UNIT provides through its subsidiary Unit Drilling Company contract drilling services in the ordinary course of its
business. UNIT also owns Superior Pipeline Company, L.L.C. which is engaged in the business of buying and building gas gathering systems. It is anticipated that the Partnership will obtain services, equipment and supplies from one or all of such
persons. In addition, UNIT may supply other goods or services to the Partnership. The terms of any contracts or agreements between the Partnership and UNIT or any affiliate will be no less favorable to the Partnership than those of comparable
contracts or agreements entered into, and will be at prices not in excess of (or in the case of purchases of production, less than) those charged in the same geographical area, by non-affiliated persons or companies dealing at arm’s length.

  
 For its services as a drilling contractor, Unit Drilling
Company will charge the Partnership on either a daywork (a specified per day rate for each day a drilling rig is on the drill site), a footage (a specified rate per foot drilled) or a turnkey (specified amount for drilling the well) basis. The rate
charged by Unit Drilling Company for such services will be the same as those offered to unaffiliated third parties in the same or similar geographic areas. 
  
 Right of Presentment Price Determination 
  
 Under the terms of the Partnership Agreement, a Limited Partner can, subject to certain conditions, require the General Partner to purchase his or her
Units at a price determined by the application of a stated formula to the estimated future net revenues attributable to the Partnership’s estimated proved reserves. See “TERMS OF THE OFFERING — Right of Presentment.” It is
anticipated that if an independent engineering firm makes an evaluation of the proved reserves of the Partnership, the result of that evaluation will be used in determining the price to be paid to a Limited Partner exercising his or her right of
presentment. However, if no such independent evaluation is made, the right of presentment purchase price will be determined by using the proved reserves and future net revenue estimates of the technical staff of the General Partner. 
  
 Receipt of Compensation Regardless of Profitability 
  
 The General Partner is entitled to receive its fees and other compensation
and reimbursements from the Partnership regardless of whether the Partnership operates at a profit or loss. See “PARTICIPATION IN COSTS AND REVENUES” and “COMPENSATION.” Such fees, compensation and reimbursements will decrease
the Limited Partners’ share of any profits generated by operations of the Partnership or increase losses if such operations should prove unprofitable. 
  
 Legal Counsel 
  
 Conner & Winters, P.C. serves as special legal counsel for the General Partner. Such firm has performed legal services for the General Partner and
UNIT and is expected to render legal services to the Partnership. Although such firm has indicated its intention to withdraw from representation of the Partnership if conflicts of interest do in fact arise, there can be no assurance that
representation of both the General Partner or UNIT and the Partnership by such firm will not be disadvantageous to the Partnership. 
  

 37 

 FIDUCIARY RESPONSIBILITY 
  
 General 
  
 Under Oklahoma law, the General Partner will have a fiduciary duty to the Limited Partners and consequently must exercise good faith, fairness and loyalty
in the handling of the Partnership’s affairs. The General Partner must provide Limited Partners (or their representatives) with timely and full information concerning matters affecting the business of the Partnership. Each Limited Partner may
inspect the Partnership’s books and records upon reasonable prior notice. The nature of the fiduciary duties of general partners is an evolving area of law and prospective investors who have questions concerning the duties of the General
Partner should consult with their counsel. 
  
 Regardless of the
fiduciary obligations of the General Partner, the General Partner, UNIT or its affiliates, subject to any restrictions or requirements set forth in the Agreement, may: 
  

	 	•	 	engage independently of the Partnership in all aspects of the oil and gas business, either for their own accounts or for the accounts of others; 

  

	 	•	 	sell interests in oil and gas properties held by them to, purchase oil and gas production from, and engage in other transactions with, the Partnership; 

  

	 	•	 	serve as general partner of other oil and gas drilling or income partnerships, including those which may be in competition with the Partnership; and 

  

	 	•	 	engage in other activities that may involve conflicts of interest. 

  
 See “CONFLICTS OF INTEREST.” Thus, unlike the strict duty of a fiduciary who must act solely in the best interests of his or her beneficiary, the Agreement
permits the General Partner to consider, among other things, the interests of other partnerships sponsored by the General Partner, UNIT or its affiliates in resolving investment and other conflicts of interest. The foregoing provisions permit the
General Partner to conduct its own operations and to act as the general partner of more than one similar partnership or investment program and for the Partnership to benefit from its experience resulting therefrom, but relieves the General Partner
of the strict fiduciary duty of a general partner acting as such for only one investment program at a time. These provisions are primarily intended to reconcile the applicable duties under Oklahoma law with the fact that the General Partner will
manage and administer its own oil and gas operations and a number of other oil and gas investment programs with which possible conflicts of interests may arise and resolve such conflicts in a manner consistent with the expectation of the investors
in all such programs, the General Partner’s fiduciary duties and customary business practices and statutes applicable thereto. 
  
 Liability and Indemnification 
  
 The Agreement provides that the General Partner will perform its duties in an efficient and businesslike manner with due caution and in accordance with
established practices of the oil and gas industry. The Agreement further provides that the General Partner and its affiliates will not be liable to the Partnership or the Partners, and will be indemnified by the Partnership, for any expense
(including attorney fees), loss or damage incurred by reason of any act or omission performed or omitted in good faith in a manner reasonably believed by the General Partner or its affiliates to be within the scope of authority and in the best
interest of the Partnership or the Partners unless the General Partner or its affiliates is guilty of gross negligence or willful misconduct. While not totally certain under Oklahoma law, absent specific provisions in the partnership agreement to
the contrary, a general partner of a limited partnership may be liable to its limited partners if it fails to conduct the partnership affairs with the same amount of care which ordinarily prudent persons would use in similar circumstances.
Consequently, the Agreement may be viewed as requiring a lesser standard of duty and care than what Oklahoma law might otherwise require of the General Partner. 
  

Any claim against the Partnership for indemnification must be satisfied only out of Partnership assets including insurance proceeds, if any, and none
of the Limited Partners will have personal liability therefore. 
  

 38 

 The Limited Partners may have more limited rights of action than they would have absent the liability and
indemnification provisions above. Moreover, indemnification enforced by the General Partner under such provisions will reduce the assets of the Partnership. It should be noted, however, that it is the position of the Securities and Exchange
Commission (“Commission”) that any attempt to limit the liability of a general partner or to indemnify a general partner under the federal securities laws is contrary to public policy and, therefore, unenforceable. The General
Partner has been advised of the position of the Commission. 
  
 Generally, the Limited Partners’ remedy for the General Partner’s breach of a fiduciary duty will be to bring a legal action against the General Partner to recover any damages, generally measured by the benefits earned by the
General Partner as a result of the fiduciary breach. Additionally, Limited Partners may also be able to obtain other forms of relief, including injunctive relief. The Act provides that a limited partner may bring an action in the name of a limited
partnership (a partnership derivative action) to recover a judgment in its favor if general partners with authority to do so have refused to bring the action or if an effort to cause such general partners to bring the action is not likely to
succeed. 
  
 PRIOR ACTIVITIES 
  
 UNIT has been engaged in oil and gas exploration and development operations
since late 1974 and has conducted oil and gas drilling programs using the limited partnership format since 1979. The following table depicts the drilling results achieved as of September 30, 2004 by UNIT during each year since 1975. Because of the
unpredictability of oil and gas exploration in general, such results should not be considered indicative of the results that may be achieved by the Partnership. 
  

																	
	 Year Ended July 31(1)

	  	Gross Wells(2)

	    	Net Wells(3)

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	 1975 Exploratory
	  	2	    	0	    	2	    	0	    	.01	    	0	    	.01	    	0
	 Development
	  	4	    	0	    	2	    	2	    	.07	    	0	    	.03	    	.04
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	6	    	0	    	4	    	2	    	.08	    	0	    	.04	    	.04
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1976 Exploratory
	  	1	    	0	    	0	    	1	    	.01	    	0	    	0	    	.01
	 Development
	  	8	    	0	    	6	    	2	    	.29	    	0	    	.28	    	.01
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	9	    	0	    	6	    	3	    	.30	    	0	    	.28	    	.02
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1977 Exploratory
	  	9	    	0	    	3	    	6	    	1.50	    	0	    	.45	    	1.05
	 Development
	  	16	    	0	    	9	    	7	    	2.00	    	0	    	.70	    	1.30
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	25	    	0	    	12	    	13	    	3.50	    	0	    	1.15	    	2.35
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1978 Exploratory
	  	8	    	1	    	1	    	6	    	1.17	    	.34	    	.15	    	.68
	 Development
	  	26	    	0	    	13	    	13	    	2.64	    	0	    	.76	    	1.88
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	34	    	1	    	14	    	19	    	3.81	    	.34	    	.91	    	2.56
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1979 Exploratory
	  	10	    	0	    	5	    	5	    	1.40	    	0	    	.76	    	.64
	 Development
	  	16	    	1	    	8	    	7	    	1.99	    	.06	    	.95	    	.98
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	26	    	1	    	13	    	12	    	3.39	    	.06	    	1.71	    	1.62
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1980 Exploratory
	  	1	    	0	    	1	    	0	    	1.28	    	0	    	.23	    	1.05
	 Development
	  	10	    	0	    	8	    	2	    	3.13	    	0	    	.85	    	2.28
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	  	11	    	0	    	9	    	2	    	4.41	    	0	    	1.08	    	3.33
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 1981 Exploratory
	  	14	    	1	    	4	    	9	    	1.12	    	.02	    	.16	    	.94
	 Development
	  	66	    	18	    	29	    	19	    	7.38	    	2.96	    	1.77	    	2.65
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	80	    	19	    	33	    	28	    	8.50	    	2.98	    	1.93	    	3.59

  

 39 

																	
	 Year Ended July 31(1)

	  	Gross Wells(2)

	    	Net Wells(3)

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	 1982 Exploratory
	  	40	    	5	    	9	    	26	    	3.39	    	.60	    	.32	    	2.47
	 Development
	  	100	    	22	    	51	    	27	    	11.70	    	4.70	    	2.71	    	4.29
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	140	    	27	    	60	    	53	    	15.09	    	5.30	    	3.03	    	6.76
									
	 1983 Exploratory
	  	6	    	2	    	0	    	4	    	1.31	    	.72	    	0	    	.59
	 Development
	  	72	    	18	    	26	    	28	    	8.01	    	3.45	    	1.17	    	3.39
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	78	    	20	    	26	    	32	    	9.32	    	4.17	    	1.17	    	3.98
									
	 1984 Exploratory
	  	2	    	1	    	1	    	0	    	.52	    	.49	    	.03	    	0
	 Development
	  	50	    	15	    	22	    	13	    	6.81	    	3.42	    	2.74	    	.65
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	52	    	16	    	23	    	13	    	7.33	    	3.91	    	2.77	    	.65
									
	 1985 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	38	    	11	    	16	    	11	    	8.32	    	2.89	    	2.39	    	3.04
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	38	    	11	    	16	    	11	    	8.32	    	2.89	    	2.39	    	3.04
									
	 1986 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	21	    	4	    	6	    	11	    	3.85	    	.81	    	1.01	    	2.03
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	21	    	4	    	6	    	11	    	3.85	    	.81	    	1.01	    	2.03
									
	 1987 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	46	    	23	    	10	    	13	    	11.91	    	7.95	    	1.76	    	2.34
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	46	    	23	    	10	    	13	    	11.91	    	7.95	    	1.76	    	2.34
									
	 1988 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	39	    	20	    	10	    	9	    	22.56	    	14.77	    	4.05	    	3.74
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	39	    	20	    	10	    	9	    	22.56	    	14.77	    	4.05	    	3.74
									
	 1989 Exploratory
	  	3	    	0	    	1	    	2	    	1.97	    	0	    	.47	    	1.50
	 Development
	  	40	    	12	    	15	    	13	    	18.83	    	8.81	    	4.13	    	5.89
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	43	    	12	    	16	    	15	    	20.80	    	8.81	    	4.60	    	7.39
									
	 1990 Exploratory
	  	5	    	0	    	2	    	3	    	1.22	    	0	    	.12	    	1.10
	 Development
	  	35	    	11	    	14	    	10	    	16.53	    	8.38	    	3.52	    	4.63
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	40	    	11	    	16	    	13	    	17.75	    	8.38	    	3.64	    	5.73
									
	 1991 Exploratory
	  	4	    	0	    	0	    	4	    	.82	    	0	    	0	    	.82
	 Development
	  	28	    	10	    	9	    	9	    	15.88	    	8.61	    	3.91	    	3.36
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	32	    	10	    	9	    	13	    	16.70	    	8.61	    	3.91	    	4.18
									
	 1992 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	18	    	1	    	11	    	6	    	5.81	    	1.00	    	3.33	    	1.48
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	18	    	1	    	11	    	6	    	5.81	    	1.00	    	3.33	    	1.48
									
	 1993 Exploratory
	  	1	    	0	    	0	    	1	    	.10	    	0	    	0	    	.10
	 Development
	  	16	    	9	    	6	    	1	    	12.48	    	8.98	    	3.32	    	.18
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	17	    	9	    	6	    	2	    	12.58	    	8.98	    	3.32	    	.28
									
	 1994 Exploratory
	  	3	    	0	    	1	    	2	    	1.71	    	0	    	.95	    	.76
	 Development
	  	57	    	5	    	40	    	12	    	25.79	    	4.75	    	14.14	    	6.90
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	60	    	5	    	41	    	14	    	27.50	    	4.75	    	15.09	    	7.66

  

 40 

																	
	 Year Ended July 31(1)

	  	Gross Wells(2)

	    	Net Wells(3)

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	 1995 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	45	    	15	    	24	    	6	    	14.94	    	4.67	    	8.04	    	2.23
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	45	    	15	    	24	    	6	    	14.94	    	4.67	    	8.04	    	2.23
									
	 1996 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	70	    	10	    	51	    	9	    	32.09	    	7.61	    	20.09	    	4.39
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	70	    	10	    	51	    	9	    	32.09	    	7.61	    	20.09	    	4.39
									
	 1997 Exploratory
	  	2	    	0	    	0	    	2	    	2.00	    	0	    	0	    	2.00
	 Development
	  	80	    	8	    	58	    	14	    	35.94	    	4.35	    	23.29	    	8.30
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	82	    	8	    	58	    	16	    	37.94	    	4.35	    	23.29	    	10.30
									
	 1998 Exploratory
	  	2	    	0	    	1	    	1	    	.63	    	0	    	.375	    	.26
	 Development
	  	76	    	3	    	52	    	21	    	30.17	    	.31	    	18.750	    	11.11
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	78	    	3	    	53	    	22	    	30.80	    	.31	    	19.125	    	11.37
									
	 1999 Exploratory
	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	 Development
	  	51	    	1	    	42	    	8	    	21.8	    	.4	    	17.4	    	4.0
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	51	    	1	    	42	    	8	    	21.8	    	.4	    	17.4	    	4.0
									
	 2000 Exploratory
	  	2	    	0	    	2	    	0	    	1.72	    	0	    	1.72	    	0
	 Development
	  	98	    	7	    	73	    	18	    	38.37	    	1.45	    	28.55	    	8.37
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	100	    	7	    	75	    	18	    	40.09	    	1.45	    	30.27	    	8.37
									
	 2001 Exploratory
	  	3	    	0	    	0	    	3	    	2.03	    	0	    	0	    	2.03
	 Development
	  	123	    	7	    	94	    	22	    	49.94	    	1.08	    	34.12	    	14.74
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	126	    	7	    	94	    	25	    	51.97	    	1.08	    	34.12	    	16.77
									
	 2002 Exploratory
	  	6	    	0	    	2	    	4	    	1.34	    	0	    	.90	    	.44
	 Development
	  	91	    	4	    	63	    	24	    	47.15	    	1.92	    	29.71	    	15.52
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	97	    	4	    	65	    	28	    	48.49	    	1.92	    	30.61	    	15.96
									
	 2003 Exploratory
	  	4	    	1	    	3	    	0	    	2.40	    	.20	    	2.20	    	0
	 Development
	  	145	    	5	    	119	    	21	    	59.17	    	2.13	    	44.31	    	12.73
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	149	    	6	    	122	    	21	    	61.57	    	2.33	    	46.51	    	12.73
									
	 Period of January 1, 2004 to September 30, 2004
	  	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 
	 Exploratory
	  	6	    	0	    	4	    	2	    	3.28	    	0	    	1.9	    	1.38
	 Development
	  	110	    	15	    	79	    	16	    	44.76	    	5.90	    	30.62	    	8.24
	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 Total
	  	116	    	15	    	83	    	18	    	48.04	    	5.90	    	32.52	    	9.62

	(1)	Except as indicated, the figures used in this table relate to wells drilled and completed during each of the 12 month periods ended July 31 or December 31, as the case may be. Oil
wells and gas wells shown include both producing wells and wells capable of production. 

	(2)	“Gross Wells” refers to the total number of wells in which there was participation by UNIT. 

	(3)	“Net Wells” refers to the aggregate leasehold working interest of UNIT in such wells. For example, a 50% leasehold working interest in a well drilled represents 1.0 Gross
Well, but a .50 Net Well. 

  
 Prior Employee Programs

  
 During the period of 1979 to 1983, persons who were
designated key employees of UNIT by its board of directors participated in the Unit Key Employee Exploration Funds (the “Funds”). These Funds were formed as general partnerships for the purpose of participating in 10% of all of the
exploration and development operations 

  

 41 

 
conducted by UNIT during a specified period. Except for the Fund formed in 1983, each of the prior Funds served as one of the general partners in at least
one of the prior drilling programs sponsored by UNIT and was allocated 10% of the expenses and revenues allocable to the general partners as a group. In each of these Funds the costs charged to it in connection with its operations were financed with
the proceeds of bank borrowings and out of the Funds’ share of revenues. 
  
 The 1983 Fund served as the sole capital limited partner in the Unit 1983-A Oil and Gas Program and as such made no contribution to the capital of that program and shared in 10% of the costs and revenues otherwise
allocable to the General Partner after the distributions to the General Partner from the program equaled the amount of its contributions thereto plus UNIT’s interest costs with respect to the unrecovered amount of its contributions. 

 
 Because of the differences in structure, format and plan of operations
between the prior Funds and the Partnership and because of the uncertainties which are inherent in oil and gas operations generally, the results achieved by the prior Funds should not be considered indicative of the results the Partnership may
achieve. 
  
 For each year from 1984 through 2004, a separate
Employee Program was formed as an Oklahoma limited partnership with UNIT or UPC as its sole general partner (UPC now serves as the sole general partner of each of these Employee Programs) and with eligible employees and directors of UNIT and its
subsidiaries who subscribed for units therein as the limited partners. Each Employee Program participated on a proportionate basis (to the extent of 10% of the General Partner’s interest in each case except for the 1986 and 1987 Employee
Programs, in which case the percentage participation was 15% and the 1992 - 2001 Employee Programs, in which case the percentage was 5% and the 2002 and 2003 Employee Programs in which case the percentage was 2 1/2% and 2004 Employee Program in which case the percentage was 1%) in all of UNIT’s oil and gas exploration and
development operations conducted during the calendar year for which the program was formed beginning with its date of formation if it was formed after January 1. Although the terms and provisions of these Employee Programs are virtually identical to
those of the Partnership, because of the unpredictability of oil and gas exploration and development in general, the results for the Employee Programs shown below should not be considered indicative of the results that may be achieved by the
Partnership. 
  
 As noted above, the Funds and the Employee
Programs have participated in a specified percentage (ranging from 1% to 15%, depending on the program) of virtually all of UNIT’s or the General Partner’s exploration and development operations conducted since the latter half of 1979.
Thus, the drilling results of these partnerships would be proportionate to those drilling results of UNIT for the periods beginning after the fiscal year ended July 31, 1979 shown above. 
  
 Results of the Prior Oil and Gas Programs 
  
 In each of the General Partner’s prior oil and gas programs other than the Unit 1983-A Oil and Gas Program and the Unit
1984 Oil and Gas Limited Partnership, one of the prior Funds also served as a general partner. The 1983 Fund served as the sole capital limited partner of the Unit 1983-A Oil and Gas Program and the 1984 Employee Program serves as a general partner
of the Unit 1984 Oil and Gas Limited Partnership. The Unit 1979 Oil and Gas Program was the first limited partnership drilling program of which UNIT was a sponsor. The revenue sharing terms of the 1979 Program was generally 70% to the limited
partners and 30% to the general partners until 150% program payout at which time the revenues were to be shared 55% to the limited partners and 45% to the general partners. The 1979 Program was dissolved effective July 1, 2003. The revenue sharing
terms of the Unit 1980 Oil and Gas Program were generally 60% to the limited partners and 40% to the general partners. The revenue sharing terms of the Unit 1981 Oil and Gas Program were generally 70% to the limited partners and 30% to the general
partners until program payout and 50% to the limited partners and 50% to the general partners thereafter. The revenue sharing terms of the Unit 1981-II Oil and Gas Program, the Unit 1982-A Oil and Gas Program and the Unit 1982-B Oil and Gas Program
(60% to the limited partners and 40% to the general partners) were substantially the same as those of the Unit 1983-A Oil and Gas Program and the Unit 1984 Oil and Gas Limited Partnership (65% to the limited partners and 35% to the general partner)
except that the general partners’ cost percentage and the general partners’ revenue share in each of those prior programs could not be less than 25%. The following tables depict the drilling results at September 30, 2003, and the economic
results at September 30, 2003 of prior oil and gas programs and the 1984 - 2003 Employee Programs. On September 12, 

  

 42 

 
1986, in connection with a major restructuring and recapitalization, UNIT acquired all of the assets and liabilities of the programs formed during 1980
through 1983 and these programs have now been dissolved. Effective December 31, 1993, pursuant to an Agreement and Plan of Merger, dated as of December 28, 1993, all of the assets and all of the liabilities of the 1984, 1985, 1986, 1987, 1988, 1989
and 1990 Employee Programs were merged with and consolidated into a new Employee Program called the Unit Consolidated Employee Oil and Gas Limited Partnership, an Oklahoma Limited Partnership which was formed November 30, 1993 (the
“Consolidated Program”). Effective December 31, 2002, pursuant to an Agreement and Plan of Merger, dated December 27, 2002, all of the assets and all of the liabilities of the 1991, 1992, 1993, 1994, 1995, 1996, 1997, 1998, and 1999
Employee Programs were merged with and consolidated into to the Consolidated Program. The Consolidated Program holds no assets other than those acquired in the mergers with the 1984 through 1999 Employee Programs. All of the Employee Programs formed
since 2000 continue in existence. Certain of these programs have not completed all of their drilling and development operations. Moreover, because of the unpredictability of oil and gas exploration and development in general, the results shown below
should not be considered indicative of the results that may be achieved by the Partnership. 
  
 DRILLING RESULTS 
  
 As of
September 30, 2004 
  

																			
	 	  	Gross Wells

	    	Net Wells

	 Programs

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	 1979(1)
	 	Exploratory Wells	  	6	    	0	    	2	    	4	    	2.43	    	0.00	    	0.65	    	1.78
	 	 	Development Wells	  	21	    	16	    	1	    	4	    	17.28	    	14.14	    	0.03	    	3.11
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	27	    	16	    	3	    	8	    	19.71	    	14.14	    	0.68	    	4.89
										
	 1980(2)
	 	Exploratory Wells	  	15	    	2	    	5	    	8	    	5.65	    	0.50	    	2.14	    	3.01
	 	 	Development Wells	  	32	    	5	    	15	    	12	    	12.77	    	1.17	    	5.75	    	5.85
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	47	    	7	    	20	    	20	    	18.42	    	1.67	    	7.89	    	8.86
										
	 1981(2)
	 	Exploratory Wells	  	11	    	1	    	4	    	6	    	4.61	    	0.33	    	0.88	    	3.40
	 	 	Development Wells	  	67	    	14	    	34	    	19	    	21.77	    	5.03	    	6.61	    	10.13
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	78	    	15	    	38	    	25	    	26.38	    	5.36	    	7.49	    	13.53
										
	 1981-II(2)
	 	Exploratory Wells	  	13	    	1	    	5	    	7	    	5.21	    	0.25	    	1.12	    	3.84
	 	 	Development Wells	  	45	    	3	    	29	    	13	    	9.07	    	0.69	    	4.78	    	3.60
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	58	    	4	    	34	    	20	    	14.28	    	0.94	    	5.90	    	7.44
										
	 1982-A(2)
	 	Exploratory Wells	  	11	    	3	    	1	    	7	    	3.55	    	0.78	    	0.00	    	2.77
	 	 	Development Wells	  	69	    	23	    	22	    	24	    	25.22	    	13.09	    	3.59	    	8.54
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	80	    	26	    	23	    	31	    	28.77	    	13.87	    	3.59	    	11.31
										
	 1982-B(2)
	 	Exploratory Wells	  	4	    	1	    	1	    	2	    	2.28	    	0.80	    	0.08	    	1.40
	 	 	Development Wells	  	41	    	16	    	9	    	16	    	18.60	    	9.47	    	1.01	    	8.12
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	45	    	17	    	10	    	18	    	20.88	    	10.27	    	1.09	    	9.52
										
	 1983-A(2)
	 	Exploratory Wells	  	1	    	1	    	0	    	0	    	1.00	    	1.00	    	0.00	    	0.00
	 	 	Development Wells	  	26	    	14	    	10	    	2	    	6.60	    	4.39	    	1.27	    	0.94
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	27	    	15	    	10	    	2	    	7.60	    	5.39	    	1.27	    	0.94
										
	 1984
	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0.00	    	0.00	    	0.00	    	0.00
	 	 	Development Wells	  	21	    	1	    	10	    	10	    	5.89	    	.38	    	3.08	    	2.43
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	21	    	1	    	10	    	10	    	5.89	    	.38	    	3.08	    	2.43

	(1)	Effective July 1, 2003 this program was dissolved. 

	(2)	On September 12, 1986, Unit acquired all of the assets and liabilities of this Program and the Program has been dissolved. 

  
  

 43 

 EMPLOYEE PROGRAMS 
  
 As of September 30, 2004 
  

																			
	 	  	Gross Wells

	    	Net Wells

	 Programs

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	1984(1)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0.00	    	0.00	    	0.00	    	0.00
	Empl.	 	Development Wells	  	25	    	4	    	12	    	9	    	.14	    	.02	    	.06	    	.06
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	25	    	4	    	12	    	9	    	.14	    	.02	    	.06	    	.06
										
	1985(1)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0.00	    	0.00	    	0.00	    	0.00
	Empl.	 	Development Wells	  	30	    	8	    	10	    	12	    	.38	    	.12	    	.08	    	.18
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	30	    	8	    	10	    	12	    	.38	    	.12	    	.08	    	.18
										
	1986(1)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0.00	    	0.00	    	0.00	    	0.00
	Empl.	 	Development Wells	  	18	    	6	    	8	    	4	    	.48	    	.12	    	.30	    	.06
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	18	    	6	    	8	    	4	    	.48	    	.12	    	.30	    	.06
										
	1987(1)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0.00	    	0.00	    	0.00	    	0.00
	Empl.	 	Development Wells	  	21	    	12	    	5	    	4	    	1.17	    	.74	    	.25	    	.18
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	21	    	12	    	5	    	4	    	1.17	    	.74	    	.25	    	.18
										
	1988(1)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	29	    	15	    	9	    	5	    	1.55	    	1.03	    	.28	    	.24
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	29	    	15	    	9	    	5	    	1.55	    	1.03	    	.28	    	.24
										
	1989(1)	 	Exploratory Wells	  	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 
	Empl.	 	Development Wells	  	32	    	7	    	14	    	11	    	1.48	    	.59	    	.36	    	.53
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	32	    	7	    	14	    	11	    	1.48	    	.59	    	.36	    	.53
										
	1990(1)	 	Exploratory Wells	  	5	    	0	    	2	    	3	    	.122	    	0	    	.01	    	.11
	Empl.	 	Development Wells	  	34	    	11	    	14	    	9	    	1.65	    	.83	    	.35	    	.46
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	39	    	11	    	16	    	12	    	1.78	    	.83	    	.36	    	.57
										
	1991(2)	 	Exploratory Wells	  	4	    	0	    	0	    	4	    	.08	    	0	    	0	    	.08
	Empl.	 	Development Wells	  	28	    	10	    	9	    	9	    	1.59	    	.86	    	.39	    	.34
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	32	    	10	    	9	    	13	    	1.67	    	.86	    	.39	    	.42
										
	1992(2)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	18	    	1	    	11	    	6	    	.29	    	.05	    	.17	    	.07
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	18	    	1	    	11	    	6	    	.29	    	.05	    	.17	    	.07
										
	1993(2)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	16	    	9	    	6	    	1	    	.63	    	.45	    	.17	    	.01
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	16	    	9	    	6	    	1	    	.63	    	.45	    	.17	    	.01
										
	1994(2)	 	Exploratory Wells	  	3	    	0	    	1	    	2	    	.09	    	0	    	.05	    	.04
	Empl.	 	Development Wells	  	57	    	5	    	40	    	12	    	1.29	    	.24	    	.70	    	.35
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	60	    	5	    	41	    	14	    	1.38	    	.24	    	.75	    	.39
										
	1995(2)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	45	    	15	    	24	    	6	    	.74	    	.23	    	.40	    	.11
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	45	    	15	    	24	    	6	    	.74	    	.23	    	.40	    	.11
										
	1996(2)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	53	    	7	    	38	    	8	    	1.24	    	.27	    	.76	    	.21
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	53	    	7	    	38	    	8	    	1.24	    	.27	    	.76	    	.21

  

 44 

																			
	 	  	Gross Wells

	    	Net Wells

	 Programs

	  	Total

	    	Oil

	    	Gas

	    	Dry

	    	Total

	    	Oil

	    	Gas

	    	Dry

	1997(2)	 	Exploratory Wells	  	2	    	0	    	0	    	2	    	.10	    	0	    	0	    	.10
	Empl.	 	Development Wells	  	80	    	8	    	58	    	14	    	1.80	    	.22	    	1.16	    	.42
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	82	    	8	    	58	    	16	    	1.90	    	.22	    	1.16	    	.52
										
	1998(2)	 	Exploratory Wells	  	2	    	0	    	1	    	1	    	.03	    	0	    	.02	    	.01
	Empl.	 	Development Wells	  	76	    	3	    	52	    	21	    	1.51	    	.02	    	.94	    	.56
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	78	    	3	    	53	    	22	    	1.54	    	.02	    	.96	    	.57
										
	1999(2)	 	Exploratory Wells	  	0	    	0	    	0	    	0	    	0	    	0	    	0	    	0
	Empl.	 	Development Wells	  	51	    	1	    	42	    	8	    	1.09	    	.02	    	.87	    	.20
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	51	    	1	    	42	    	8	    	1.09	    	.02	    	.87	    	.20
										
	2000	 	Exploratory Wells	  	2	    	0	    	2	    	0	    	.09	    	0	    	.09	    	0
	Empl.	 	Development Wells	  	98	    	7	    	73	    	18	    	1.92	    	.07	    	1.43	    	.42
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	100	    	7	    	75	    	18	    	2.01	    	.07	    	1.52	    	.42
										
	2001	 	Exploratory Wells	  	3	    	0	    	0	    	3	    	.05	    	0	    	0	    	.05
	Empl.	 	Development Wells	  	123	    	7	    	94	    	22	    	1.25	    	.03	    	.85	    	.37
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	126	    	7	    	94	    	25	    	1.30	    	.03	    	.85	    	.42
										
	2002	 	Exploratory Wells	  	6	    	0	    	2	    	4	    	.03	    	0	    	.02	    	.01
	Empl.	 	Development Wells	  	91	    	4	    	63	    	24	    	1.18	    	.05	    	.74	    	.39
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	97	    	4	    	65	    	28	    	1.21	    	.05	    	.76	    	.40
										
	2003	 	Exploratory Wells	  	4	    	1	    	3	    	0	    	.03	    	.01	    	.02	    	0
	Empl.	 	Development Wells	  	145	    	5	    	119	    	21	    	.59	    	.02	    	.44	    	.13
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	149	    	6	    	122	    	21	    	.62	    	.03	    	.46	    	.13
									
	 Period of January 1, 2004
	  	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 
	 To September 30, 2004
	  	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 
										
	 2004
	 	Exploratory Wells	  	6	    	0	    	4	    	2	    	.03	    	0	    	.02	    	.01
	 Empl.
	 	Development Wells	  	110	    	15	    	79	    	16	    	.45	    	.06	    	.31	    	.08
	 	 	 	  	
	    	
	    	
	    	
	    	
	    	
	    	
	    	

	 	 	Total	  	116	    	15	    	83	    	18	    	.48	    	.06	    	.33	    	.09

	(1)	Effective December 31, 1993 this Program was merged with and into the Consolidated Program. 

	(2)	Effective December 31, 2002 this Program was merged with and into the Consolidated Program. 

  

 45 

 GENERAL PARTNERS’ PAYOUT TABLE(1) 
  
 As of September 30, 2004 
  

									
	 Program

	  	Total
Expenditures
Including
Operating
Costs(2)

	  	Total
Revenues
Before
Deducting
Operating
Costs

	  	 Total Revenues
Before Deducting
Operating
Costs
for 3 Months Ended
 September 30, 2004

	 1979(***)
	  	$	8,781,728	  	$	10,846,983	  	—  
	 1980
	  	 	4,043,599	  	 	4,044,424	  	—  
	 1981
	  	 	8,325,594	  	 	6,338,173	  	—  
	 1981-II
	  	 	6,642,875	  	 	3,995,616	  	—  
	 1982-A
	  	 	9,190,842	  	 	6,782,893	  	—  
	 1982-B
	  	 	4,213,710	  	 	3,126,326	  	—  
	 1983-A
	  	 	2,277,514	  	 	1,312,531	  	—  
	 1984
	  	 	2,643,375	  	 	2,407,301	  	38,597
	 1984 Employee(*)
	  	 	1,542	  	 	1,745	  	—  
	 1985 Employee(*)
	  	 	2,820	  	 	1,808	  	—  
	 1986 Energy Income Fund(**)
	  	 	1,937,279	  	 	1,933,107	  	19,219
	 1986 Employee(*)
	  	 	4,403	  	 	6,813	  	—  
	 1987 Employee(*)
	  	 	624,354	  	 	815,358	  	—  
	 1988 Employee(*)
	  	 	1,196,564	  	 	1,588,132	  	—  
	 1989 Employee(*)
	  	 	1,424,525	  	 	1,171,961	  	—  
	 1990 Employee(*)
	  	 	653,563	  	 	525,572	  	—  
	 1991 Employee(****)
	  	 	2,352,323	  	 	3,046,177	  	—  
	 1992 Employee(****)
	  	 	241,577	  	 	400,556	  	—  
	 1993 Employee(****)
	  	 	496,051	  	 	717,460	  	—  
	 1994 Employee(****)
	  	 	1,435,412	  	 	1,841,119	  	—  
	 1995 Employee(****)
	  	 	476,082	  	 	599,485	  	—  
	 1996 Employee(****)
	  	 	901,692	  	 	869,473	  	—  
	 1997 Employee(****)
	  	 	1,296,424	  	 	1,165,747	  	—  
	 1998 Employee(****)
	  	 	1,180,292	  	 	1,083,527	  	—  
	 1999 Employee(****)
	  	 	953,718	  	 	1,314,469	  	—  
	 Consolidated Program
	  	 	11,715	  	 	31,411	  	2,267
	 2000 Employee
	  	 	1,998,919	  	 	2,381,577	  	84,751
	 2001 Employee
	  	 	973,190	  	 	708,189	  	48,657
	 2002 Employee
	  	 	1,010,082	  	 	724,120	  	67,250
	 2003 Employee
	  	 	2,723,826	  	 	1,028,607	  	207,511
	 2004 Employee
	  	 	269,447	  	 	37,368	  	29,051

	(*)	Effective December 31, 1993, this program was merged with and into the Consolidated Program. 

	(**)	Formed primarily for purposes of acquiring producing oil and gas properties. 

	(***)	Effective July 1, 2003 this program was dissolved. 

	(****)	Effective December 31, 2002 this Program was merged with and into the Consolidated Program. 

  

 46 

 LIMITED PARTNERS’ PAYOUT TABLE(1) 
  
 As of September 30, 2004 
  

									
	 Program

	  	Total
Expenditures
Including
Operating
Costs(2)

	  	Total
Revenues
Before
Deducting
Operating
Costs

	  	Total Revenues
Before Deducting
Operating Costs
for 3 Months Ended
September 30, 2004

	 1979(***)
	  	$	14,729,990	  	$	18,839,040	  	—  
	 1980
	  	 	17,688,367	  	 	6,949,008	  	—  
	 1981
	  	 	37,073,946	  	 	15,768,826	  	—  
	 1981-II
	  	 	18,638,600	  	 	7,028,946	  	—  
	 1982-A
	  	 	24,866,078	  	 	12,708,949	  	—  
	 1982-B
	  	 	12,069,566	  	 	5,367,312	  	—  
	 1983-A
	  	 	3,770,856	  	 	1,922,177	  	—  
	 1984
	  	 	3,178,371	  	 	2,501,903	  	38,597
	 1984 Employee(*)
	  	 	120,942	  	 	171,540	  	—  
	 1985 Employee(*)
	  	 	277,901	  	 	178,984	  	—  
	 1986 Energy Income Fund(**)
	  	 	2,876,397	  	 	4,019,413	  	28,828
	 1986 Employee(*)
	  	 	435,858	  	 	676,972	  	—  
	 1987 Employee(*)
	  	 	341,846	  	 	469,830	  	—  
	 1988 Employee(*)
	  	 	333,898	  	 	446,044	  	—  
	 1989 Employee(*)
	  	 	179,593	  	 	175,331	  	—  
	 1990 Employee(*)
	  	 	300,852	  	 	188,848	  	—  
	 1991 Employee(****)
	  	 	620,136	  	 	811,871	  	—  
	 1992 Employee(****)
	  	 	622,697	  	 	1,033,805	  	—  
	 1993 Employee(****)
	  	 	451,551	  	 	664,349	  	—  
	 1994 Employee(****)
	  	 	582,274	  	 	754,012	  	—  
	 1995 Employee(****)
	  	 	762,211	  	 	941,188	  	—  
	 1996 Employee(****)
	  	 	549,125	  	 	534,519	  	—  
	 1997 Employee(****)
	  	 	605,116	  	 	524,732	  	—  
	 1998 Employee(****)
	  	 	613,890	  	 	551,342	  	—  
	 1999 Employee(****)
	  	 	289,622	  	 	392,633	  	—  
	 Consolidated Program
	  	 	1,071,954	  	 	3,106,696	  	224,243
	 2000 Employee
	  	 	279,893	  	 	324,880	  	11,557
	 2001 Employee
	  	 	436,681	  	 	318,172	  	21,860
	 2002 Employee
	  	 	519,497	  	 	373,032	  	34,644
	 2003 Employee
	  	 	621,830	  	 	210,394	  	42,503
	 2004 Employee
	  	 	211,708	  	 	29,360	  	22,826

	(*)	Effective December 31, 1993, this program was merged with and into the Consolidated Program. 

	(**)	Formed primarily for purposes of acquiring producing oil and gas properties. 

	(***)	Effective July 1, 2003, this program was dissolved. 

	(****)	Effective December 31, 2002 this Program was merged with and into the Consolidated Program. 

  

 47 

 GENERAL PARTNERS’ NET CASH TABLE (1) 
  
 As of September 30, 2004 
  

																	
	 Program

	  	Total
Expenditures
Less
Operating
Costs(2)

	  	Total
Revenues
Less
Operating
Costs

	  	 Total
Revenues
Less
Operating
Costs for
 3 Months
Ended
Sept. 30,
2004

	 	 	Total
Revenues
Distributed

	  	 Total
Revenues
Distributed
for 3 Months
Ended
 Sept. 30,
2004

	 1979(***)
	  	$	2,805,917	  	$	4,871,172	  	$	—  	 	 	$	3,961,014	  	$	—  
	 1980
	  	 	2,628,978	  	 	2,629,803	  	 	—  	 	 	 	2,635,751	  	 	—  
	 1981
	  	 	6,546,160	  	 	4,558,739	  	 	—  	 	 	 	5,368,272	  	 	—  
	 1981-II
	  	 	4,817,145	  	 	2,169,886	  	 	—  	 	 	 	2,609,000	  	 	—  
	 1982-A
	  	 	6,297,972	  	 	3,890,023	  	 	—  	 	 	 	3,755,000	  	 	—  
	 1982-B
	  	 	2,565,504	  	 	1,478,120	  	 	—  	 	 	 	1,158,000	  	 	—  
	 1983-A
	  	 	1,380,331	  	 	415,348	  	 	—  	 	 	 	819,000	  	 	—  
	 1984
	  	 	947,599	  	 	711,525	  	 	9,989	 	 	 	1,036,584	  	 	9,000
	 1984 Employee(*)
	  	 	874	  	 	1,077	  	 	—  	 	 	 	1,000	  	 	—  
	 1985 Employee(*)
	  	 	2,300	  	 	1,288	  	 	—  	 	 	 	1,035	  	 	—  
	 1986 Energy Income Fund(**)
	  	 	172,719	  	 	168,547	  	 	(3,233	)	 	 	473,865	  	 	1,000
	 1986 Employee(*)
	  	 	2,698	  	 	5,108	  	 	 	 	 	 	4,486	  	 	—  
	 1987 Employee(*)
	  	 	357,368	  	 	548,372	  	 	—  	 	 	 	465,800	  	 	—  
	 1988 Employee(*)
	  	 	770,272	  	 	1,161,840	  	 	—  	 	 	 	942,800	  	 	—  
	 1989 Employee(*)
	  	 	1,010,133	  	 	752,569	  	 	—  	 	 	 	607,900	  	 	—  
	 1990 Employee(*)
	  	 	466,272	  	 	338,281	  	 	—  	 	 	 	266,600	  	 	—  
	 1991 Employee(****)
	  	 	1,056,956	  	 	1,750,810	  	 	—  	 	 	 	1,618,020	  	 	—  
	 1992 Employee(****)
	  	 	99,250	  	 	258,229	  	 	—  	 	 	 	230,839	  	 	—  
	 1993 Employee(****)
	  	 	311,650	  	 	533,059	  	 	—  	 	 	 	472,480	  	 	—  
	 1994 Employee(****)
	  	 	856,390	  	 	1,262,097	  	 	—  	 	 	 	1,076,708	  	 	—  
	 1995 Employee(****)
	  	 	330,617	  	 	454,020	  	 	—  	 	 	 	350,504	  	 	—  
	 1996 Employee(****)
	  	 	681,656	  	 	649,437	  	 	—  	 	 	 	450,383	  	 	—  
	 1997 Employee(****)
	  	 	1,057,002	  	 	926,325	  	 	—  	 	 	 	695,477	  	 	—  
	 1998 Employee(****)
	  	 	920,862	  	 	824,096	  	 	—  	 	 	 	638,218	  	 	—  
	 1999 Employee(****)
	  	 	706,281	  	 	1,067,032	  	 	—  	 	 	 	796,578	  	 	—  
	 Consolidated Program
	  	 	23,823	  	 	20,322	  	 	1,546	 	 	 	18,997	  	 	1,500
	 2000 Employee
	  	 	1,545,693	  	 	1,928,351	  	 	69,224	 	 	 	1,245,669	  	 	70,000
	 2001 Employee
	  	 	861,561	  	 	596,561	  	 	40,775	 	 	 	389,000	  	 	43,000
	 2002 Employee
	  	 	903,599	  	 	617,636	  	 	56,805	 	 	 	310,500	  	 	50,000
	 2003 Employee
	  	 	2,549,030	  	 	853,812	  	 	168,596	 	 	 	265,000	  	 	185,000
	 2004 Employee
	  	 	266,006	  	 	33,926	  	 	26,202	 	 	 	—  	  	 	—  

	(*)	Effective December 31, 1993, this program was merged with and into the Consolidated Program. 

	(**)	Formed primarily for purposes of acquiring producing oil and gas properties. 

	(***)	Effective July 1, 2003, this program was dissolved. 

	(****)	Effective December 31, 2002 this Program was merged with and into the Consolidated Program. 

  

 48 

 LIMITED PARTNERS’ NET CASH TABLE(1) 
  
 As of September 30, 2004 
  

																						
	 Program

	  	Capital
Contributed

	 	 	Total
Expenditures
Less
Operating
Costs(2)

	  	 Total
Revenues
 Less
Operating
Costs

	  	 Total
Revenues
Less
Operating
Costs for
 3 Months
Ended
Sept. 30,
2004

	 	 	Total
Revenues
Distributed

	  	Total Revenues
Distributed
for 3 Months
Ended Sept. 30,
2004

	 
	 1979(***)
	  	$	3,000,000	 	 	$	6,085,402	  	$	10,194,451	  	$	—  	 	 	$	6,198,801	  	$	—  	 
	 1980
	  	 	12,000,000	(3)	 	 	14,469,265	  	 	3,729,906	  	 	—  	 	 	 	760,000	  	 	—  	 
	 1981
	  	 	29,255,000	(4)	 	 	32,700,741	  	 	11,395,621	  	 	—  	 	 	 	5,335,065	  	 	—  	 
	 1981-II
	  	 	15,000,000	 	 	 	16,603,760	  	 	4,994,106	  	 	—  	 	 	 	1,710,001	  	 	—  	 
	 1982-A
	  	 	21,140,000	 	 	 	21,591,442	  	 	9,434,313	  	 	—  	 	 	 	6,342,000	  	 	—  	 
	 1982-B
	  	 	10,555,000	 	 	 	9,935,850	  	 	3,233,596	  	 	—  	 	 	 	2,828,740	  	 	—  	 
	 1983-A
	  	 	2,530,000	 	 	 	2,993,705	  	 	1,145,026	  	 	—  	 	 	 	227,700	  	 	—  	 
	 1984
	  	 	1,875,000	 	 	 	2,036,778	  	 	1,360,309	  	 	31,241	 	 	 	1,035,761	  	 	22,680	(5)
	 1984 Employee(*)
	  	 	174,000	 	 	 	86,664	  	 	137,262	  	 	—  	 	 	 	125,280	  	 	—  	 
	 1985 Employee(*)
	  	 	283,500	 	 	 	227,670	  	 	128,753	  	 	—  	 	 	 	182,644	  	 	—  	 
	 1986 Energy Income Fund(**)
	  	 	1,000,000	 	 	 	981,578	  	 	2,124,594	  	 	(4,852	)	 	 	2,020,000	  	 	9,900	(6)
	 1986 Employee(*)
	  	 	229,750	 	 	 	267,008	  	 	508,122	  	 	—  	 	 	 	460,007	  	 	—  	 
	 1987 Employee(*)
	  	 	209,000	 	 	 	207,060	  	 	335,044	  	 	—  	 	 	 	324,845	  	 	—  	 
	 1988 Employee(*)
	  	 	177,000	 	 	 	214,712	  	 	326,858	  	 	—  	 	 	 	281,630	  	 	—  	 
	 1989 Employee(*)
	  	 	157,000	 	 	 	157,306	  	 	153,044	  	 	—  	 	 	 	147,737	  	 	—  	 
	 1990 Employee(*)
	  	 	253,000	 	 	 	254,483	  	 	142,479	  	 	—  	 	 	 	180,895	  	 	—  	 
	 1991 Employee(****)
	  	 	263,000	 	 	 	275,590	  	 	467,325	  	 	—  	 	 	 	438,947	  	 	—  	 
	 1992 Employee(****)
	  	 	240,000	 	 	 	256,030	  	 	667,138	  	 	—  	 	 	 	626,888	  	 	—  	 
	 1993 Employee(****)
	  	 	245,000	 	 	 	281,201	  	 	493,998	  	 	—  	 	 	 	459,375	  	 	—  	 
	 1994 Employee(****)
	  	 	284,000	 	 	 	345,243	  	 	516,980	  	 	—  	 	 	 	433,668	  	 	—  	 
	 1995 Employee(****)
	  	 	454,000	 	 	 	493,337	  	 	672,314	  	 	—  	 	 	 	572,524	  	 	—  	 
	 1996 Employee(****)
	  	 	437,000	 	 	 	419,615	  	 	405,010	  	 	—  	 	 	 	382,812	  	 	—  	 
	 1997 Employee(****)
	  	 	413,000	 	 	 	495,786	  	 	415,402	  	 	—  	 	 	 	348,159	  	 	—  	 
	 1998 Employee(****)
	  	 	471,000	 	 	 	486,317	  	 	423,769	  	 	—  	 	 	 	398,937	  	 	—  	 
	 1999 Employee(****)
	  	 	141,000	 	 	 	214,376	  	 	317,387	  	 	—  	 	 	 	288,204	  	 	—  	 
	 Consolidated
	  	 	—  	 	 	 	2,184,200	  	 	2,010,889	  	 	150,923	 	 	 	1,969,997	  	 	156,675	(7)
	 2000 Employee
	  	 	199,000	 	 	 	215,129	  	 	260,117	  	 	9,447	 	 	 	237,055	  	 	9,353	(8)
	 2001 Employee
	  	 	370,000	 	 	 	387,078	  	 	268,570	  	 	18,320	 	 	 	210,530	  	 	17,760	(9)
	 2002 Employee
	  	 	457,000	 	 	 	465,490	  	 	319,025	  	 	29,266	 	 	 	250,893	  	 	25,135	(10)
	 2003 Employee
	  	 	284,000	 	 	 	586,455	  	 	175,019	  	 	34,548	 	 	 	101,104	  	 	30,956	(11)
	 2004 Employee
	  	 	434,000	 	 	 	209,004	  	 	26,656	  	 	20,588	 	 	 	—  	  	 	—  	 

	(*)	Effective December 31, 1993, this program was merged with and into the Consolidated Program. 

	(**)	Formed primarily for purposes of acquiring producing oil and gas properties. 

	(***)	Effective July 1, 2003, this program was dissolved. 

	(****)	Effective December 31, 2002 this Program was merged with and into the Consolidated Program. 

  

 49 

	(1)	Amounts reflect the accrual method of accounting. 

	(2)	Does not include expenditures of $237,600, $920,453, $2,252,900, $1,480,248, $2,079,268, $985,371 and $241,076 which were obtained from bank borrowings and used to pay the limited
partners’ share of sales commissions of $237,600, $722,453, $1,940,400, $1,183,248, $1,656,468, $827,046 and $190,476 and organization costs of $—0—, $198,000, $312,500, $297,000, $422,800, $158,325 and $50,600 for the 1979, 1980,
1981, 1981-II, 1982-A, 1982-B and 1983-A Programs, respectively. 

	(3)	Includes original subscriptions of limited partners totaling $10,000,000 and additional assessments totaling $2,000,000. 

	(4)	Includes original subscriptions of limited partners totaling $25,000,000 and additional assessments totaling $4,255,000. 

	(5)	In November 2004 the 1984 Program made a distribution of $31,185 to that program’s limited partners. 

	(6)	In November 2004 the 1986 Program made a distribution of $11,700 to that program’s limited partners. 

	(7)	In November 2004 the Consolidated Employee Program made a distribution of $152,224 to that program’s limited partners. 

	(8)	In November 2004 the 2000 Employee Program made a distribution of $8,358 to that program’s limited partners. 

	(9)	In November 2004 the 2001 Employee Program made a distribution of $17,390 to that program’s limited partners. 

	(10)	In November 2004 the 2002 Employee Program made a distribution of $26,963 to that program’s limited partners. 

	(11)	In November 2004 the 2003 Employee Program made a distribution of $37,772 to that program’s limited partners. 

  
 FEDERAL INCOME TAX CONSIDERATIONS 
  
 The following is a summary of the opinions of Conner & Winters on all
material federal income tax consequences to the Partnership and to the Limited Partners. The full tax opinion of Conner & Winters is attached to this Memorandum as Exhibit B. All prospective investors should review Exhibit B in its entirety
before investing in the Partnership. There may be aspects of a particular investor’s tax situation which are not addressed in the following discussion or in Exhibit B. Additionally, the resolution of certain tax issues depends upon future facts
and circumstances not known to Conner & Winters as of the date of this Memorandum; thus, no assurance as to the final resolution of such issues should be drawn from the following discussion. 
  
 The following statements are based upon the provisions of the Code, existing
and proposed regulations promulgated under the Code (“Regulations”), current administrative rulings, and court decisions. It is possible that legislative or administrative changes or future court decisions may significantly modify the
statements and opinions expressed herein. Such changes could be retroactive with respect to transactions occurring prior to the date of such changes. 
  
 Moreover, uncertainty exists concerning some of the federal income tax aspects of the transactions being undertaken by the Partnership. Some of the tax
positions being taken by the Partnership may be challenged by the Service. Thus, there can be no assurance that all of the anticipated tax benefits of an investment in the Partnership will be realized. 
  
 Conner & Winters’ opinion is based upon the transactions described
in this Memorandum (the “Transaction”) and upon facts as they have been represented to Conner & Winters or determined by it as of the date of the opinion. Any alteration of the facts could render the conclusions in the opinion
inapplicable. 
  

 50 

 Because of the factual nature of the inquiry, and in certain cases the lack of clear authority in the
law, it is not possible to reach a judgment as to the outcome on the merits (either favorable or unfavorable) of certain material federal income tax issues as described more fully herein. 
  
 Summary of Conclusions 
  
 Opinions expressed: The following is a summary of the specific federal income tax opinions rendered by Conner & Winters in Exhibit B.

  
 1. The material federal income tax benefits in the aggregate
from an investment in the Partnership will be realized. 
  
 2. The
Partnership will be treated as a partnership for federal income tax purposes and not as a corporation, an association taxable as a corporation or a “publicly traded partnership”. See “Partnership Status”; “Federal Taxation
of Partnerships.” 
  
 3. To the extent the Partnership’s
wells are timely drilled and its drilling costs are timely paid, the Partners will be entitled to their pro rata shares of the Partnership’s intangible drilling and development costs (“IDC”) paid in 2005. See “Intangible Drilling
and Development Costs Deductions.” 
  
 4. Most Limited
Partners’ Units will be considered as ownership interests in a passive activity within the meaning of Code Section 469 and losses generated therefrom will be limited by the passive activity provisions of the Code. See “Passive Loss and
Credit Limitations.” 
  
 5. To the extent provided herein,
the Partners’ distributive shares of Partnership tax items will be determined and allocated substantially in accordance with the terms of the Partnership Agreement. See “Partnership Allocations.” 
  
 6. The Partnership will not be required to register with the Service as a tax
shelter. See “Registration as a Tax Shelter.” 
  
 No opinion expressed: Due to the lack of authority regarding, or the essentially factual nature of, the issue, Conner & Winters expresses no opinion as to: 
  
 1. The impact of an investment in the Partnership on an investor’s alternative minimum tax liability, due to the
factual nature of the issue (See “Alternative Minimum Tax”); 
  
 2. Whether each Partner will be entitled to percentage depletion since such a determination is dependent upon the status of the Partner as an independent producer and on the Partner’s other oil and gas production; due to the inherently
factual nature of such a determination, Conner & Winters is unable to render an opinion as to the availability of percentage depletion (See “Depletion Deductions”); 
  
 3. Whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as
nominee for the Partnership. 
  
 Facts and
Representations: In rendering its opinion, Conner & Winters relied upon certain representations made to it by the General Partner, including the following: 
  
 1. The Partnership Agreement to be entered into by and among the General Partner and Limited Partners and any amendments
thereto will be duly executed and will be made available to any Limited Partner upon written request. The Partnership Agreement will be duly recorded in all places required under the Oklahoma Revised Uniform Limited Partnership Act (the
“Act”) for the due formation of the Partnership and for the continuation thereof in accordance with the terms of the Partnership Agreement. The Partnership will at all times be operated in accordance with the terms of the
Partnership Agreement, the Memorandum, and the Act. 
  
 2. No
election will be made by the Partnership, Limited Partners, or General Partner to be excluded from the application of the provisions of Subchapter K of the Code. 
  
 3. The Partnership will own operating mineral interests, as defined in the Code and in the Regulations, and none of the
Partnership’s revenues will be from non-working interests. 
  
 4. The General Partner will cause the Partnership to properly elect to deduct currently all IDC. 
  

 51 

 5. The Partnership will have a December 31 taxable year and will report its income on the accrual basis.

  
 6. All Partnership wells will be spudded by not later than
December 31, 2005. The entire amount to be paid under any drilling and operating agreements entered into by the Partnership will be attributable to IDC. 
  
 7. Such drilling and operating agreements will be duly executed and will govern the operation of the Partnership’s wells. 
  
 8. Based upon the General Partner’s review of its experience with its
previous oil and gas partnerships for the past several years and upon the intended operations of the Partnership, the General Partner believes that the sum of (i) the aggregate deductions, including depletion deductions, and (ii) 350 percent of the
aggregate tax credits from the Partnership will not, as of the close of any of the first five years ending after the date on which Units are offered for sale, exceed two times the aggregate cash invested by the Partners in the Partnership as of such
dates. In that regard, the General Partner has reviewed the economics of its similar oil and gas partnerships for the past several years, and has represented that it has determined that none of those partnerships has resulted in a “tax shelter
ratio”, as such term is defined in the Code and Regulations, greater than two to one. Further, the General Partner has represented that the deductions that are or will be represented as potentially allowable to an investor will not result in
the Partnership having a tax shelter ratio, as such term is defined in the Code and Regulations, greater than two to one. 
  
 9. The General Partner believes that at least 90% of the gross income of the Partnership will constitute income derived from the exploration, development,
production, and/or marketing of oil and gas. The General Partner does not believe that any market will ever exist for the sale of Units and the General Partner will not make a market for the Units. Further, the Units will not be traded on an
established securities market. 
  
 10. The Partnership and each
Partner will have the objective of carrying on the business of the Partnership for profit and dividing the gain therefrom. 
  
 11. The General Partner will, as nominee for the Partnership, acquire and hold title to Partnership Properties on behalf of the Partnership; the General
Partner will enter into an agency agreement before the General Partner acquires any such oil and gas properties on behalf of the Partnership; the agency agreement will reflect that the General Partner’s acquisition of Partnership properties is
on behalf of the Partnership; and the General Partner will execute assignments of all oil and gas interests acquired by it on behalf of the Partnership to the Partnership. 
  
 The opinions of Conner & Winters are also subject to all the assumptions, qualifications, and limitations set forth in
the following discussion and in the opinion, including the assumptions that each of the Partners has full power, authority, and legal right to enter into and perform the terms of the Partnership Agreement and to take any and all actions thereunder
in connection with the transactions contemplated thereby. 
  
 Each
prospective investor should be aware that, unlike a ruling from the Service, an opinion of Conner & Winters represents only Conner & Winters’ best judgment. THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT SUCCESSFULLY ASSERT
POSITIONS WHICH ARE INCONSISTENT WITH THE OPINIONS OF CONNER & WINTERS SET FORTH IN THIS DISCUSSION AND EXHIBIT B OR IN THE TAX REPORTING POSITIONS TAKEN BY THE PARTNERS OR THE PARTNERSHIP. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS OR HER OWN
TAX ADVISOR TO DETERMINE THE EFFECT OF THE TAX ISSUES DISCUSSED HEREIN AND IN EXHIBIT B ON HIS OR HER INDIVIDUAL TAX SITUATION. 
  
 General Tax Effects of Partnership Structure 
  
 The Partnership will be formed as a limited partnership pursuant to the Partnership Agreement and the laws of the State of Oklahoma. No tax ruling will
be sought from the Service as to the status of the Partnership as a partnership for federal income tax purposes. The applicability of the federal income tax consequences described herein depends on the treatment of the Partnership as a
partnership for federal income tax purposes and not as a corporation and not as an association taxable as a corporation. Any tax benefits anticipated from an investment in the Partnership would be adversely affected or eliminated if the Partnership
were treated as a corporation for federal income tax purposes. 
  

 52 

 Conner & Winters is of the opinion that, at the time of its formation, the Partnership will be
treated as a partnership for federal income tax purposes. The opinion is based on the provisions of the Partnership Agreement, applicable state and federal law and representations made by the General Partner 
  
 Under the Code, a partnership is not a taxable entity and, accordingly,
incurs no federal income tax liability. Rather, a partnership is a “pass-through” entity which is required to file an information income tax return with the Service. In general, the character of a partner’s share of each item of
income, gain, loss, deduction, and credit is determined at the partnership level. Each partner is allocated a distributive share of such items in accordance with the partnership agreement and is required to take such items into account in
determining the partner’s income. Each partner includes such amounts in determining his or her income for any taxable year of the partnership ending within or with the taxable year of the partner, without regard to whether the partner has
received or will receive any cash distributions from the partnership. 
  
 Ownership of Partnership Properties 
  
 The General Partner has indicated that it, as nominee for the Partnership (the “Nominee”), will acquire and hold title to Partnership Properties on behalf of the Partnership. The Nominee and the Partnership will enter into
an agency agreement before the Nominee acquires any oil and gas properties on behalf of the Partnership. That agency agreement will reflect that the Nominee’s acquisition of Partnership Properties is on behalf of the Partnership. The Nominee
will execute assignments of all oil and gas interest acquired by the Nominee on behalf of the Partnership to the Partnership. For various cost and procedural reasons, the assignments will not be recorded in the real estate records in the counties in
which the Partnership Properties are located. That is, while the Partnership will be the owner of the Partnership Properties, there will be no public record of that ownership. It is possible that the Service could assert that the Nominee should be
treated for federal income tax purposes as the owner of the Partnership Properties, notwithstanding the assignment of those Partnership Properties to the Partnership. If the Service were to argue successfully that the Nominee should be treated as
the tax owner of the Partnership Properties, there would be significant adverse federal income tax consequences to the Limited Partners, such as the unavailability of depletion deductions in respect of income from Partnership Properties. The Service
is concerned that taxpayers not be able to shift the tax consequences of transactions between parties based on the parties’ declaration that one party is the agent of another; the Service generally requires that taxpayers respect the form of
their transactions and ownership of property. Based on this concern, the Service may challenge the Partnership’s treatment of Partnership Properties, and tax attributes thereof, which are held of record by the Nominee. 
  
 In Commissioner of Internal Revenue v. Bollinger, 485 U.S. 340 (1988),
the United States Supreme Court reviewed a principal-agent relationship and held for the taxpayer in concluding that the principal should be treated as the tax owner of property held in the name of the agent. In that case the Supreme Court noted
that “It seems to us that the genuineness of the agency relationship is adequately assured, and tax-avoiding manipulation adequately avoided, when the fact that the corporation is acting as agent for its shareholders with respect to a
particular asset is set forth in a written agreement at the time the asset is acquired, the corporation functions as agent and not principal with respect to the asset for all purposes, and the corporation is held out as the agent and not principal
in all dealings with third parties relating to the asset.” While the Partnership and the Nominee will have in place an agreement defining their relationship before any Partnership Properties are acquired by the Nominee and the Nominee will
function as agent with respect to those Partnership Properties on behalf of the Partnership, the Nominee will not hold itself out to all third parties as the agent of the Partnership in dealings relating to the Partnership Properties. Unlike the
relationship between the principal and the agent in Bollinger, the Nominee will, however, assign title to Partnership Properties to the Partnership, but will not record those assignments. Accordingly, the facts related to the relationship
between the Nominee and the Partnership are not the same as the facts in Bollinger and it is not clear that the failure of the Nominee to hold itself out to third parties as the agent of the Partnership in dealings relating to Partnership
Properties should result in the treatment of the Nominee as the tax owner of the Partnership Properties. For the foregoing reasons, Conner & Winters have not expressed an opinion on this issue, but Conner & Winters believe that substantial
arguments may be made that the Partnership should be treated as the tax owner of Partnership Properties acquired by the Nominee on the Partnership’s behalf. If the Partnership were not treated as the tax owner of Partnership Properties, then
the following discussions which relate to the Partners’ deduction of tax items which are derived from Partnership Properties, such as IDC, depletion and depreciation, would not be applicable. 
  

 53 

 Intangible Drilling and Development Costs Deductions 
  
 Congress granted to the Secretary of the Treasury the authority to prescribe
regulations that would allow taxpayers the option of deducting, rather than capitalizing, IDC. The Secretary’s rules state that, in general, the option to deduct IDC applies only to expenditures for drilling and development items that do not
have a salvage value. 
  
 The Memorandum provides that 75% of the
Partners’ capital contributions will be utilized for IDC, which will flow through to the Partners as a deductible item in the year of investment. The deduction of IDC by most Limited Partners generally will be available only to offset passive
income. Based on a deduction of 75% of a Partner’s capital contribution, a one Unit ($1,000) investor in a 35% marginal Federal tax bracket could possibly reduce taxes payable by $262. The investor might also realize additional tax savings on
income taxes in the state in which such investor resides. 
  
 Classification of Costs. In general, IDC consists of those costs which in and of themselves have no salvage value. In previous partnerships for which the General Partner has served as general partner, intangible drilling and
development costs have ranged from 72% to 27% of the investors’ contributions. While the planned activities of the Partnership are similar in nature to those of prior partnerships, the amount of expenditures classified as IDC could be greater
or less than for prior partnerships. In addition, a partnership’s classification of a cost as IDC is not binding on the Service, which might reclassify an item labeled as IDC as a cost which must be capitalized. To the extent not deductible,
such amounts will be included in the Partnership’s basis in a mineral property and in the Partners’ tax basis in their interests in the Partnership. 
  

Timing of Deductions. Although the Partnership will elect to deduct IDC, each investor has an option of deducting IDC, or capitalizing
all or a part of the IDC and amortizing it on a straight-line basis over a sixty-month period, beginning with the taxable month in which the expenditure is made. In addition to the effect of this change on regular taxable income, the two methods
have different treatment under the Alternative Minimum Tax (“AMT”) (see “Alternative Minimum Tax”). 
  
 Although the General Partner will attempt to satisfy each requirement for deductibility of the Partnership’s IDC in 2005, no assurance can be given
that the Service will not successfully contend that the IDC of a Partnership well which is not completed until 2006 is not deductible in whole or in part until 2006. Furthermore, no assurance can be given that the Service will not challenge the
current deduction of IDC because of the prepayment being made to a related party. If the Service were successful with such a challenge, the Partners’ deductions for IDC would be deferred to later years. 
  
 Recapture of IDC. IDC previously deducted that is allocable to
a property (directly or through the ownership of an interest in a partnership) and which, if capitalized, would have been included in the adjusted basis of the property is recaptured as ordinary income to the extent of any gain realized upon the
disposition of the property. Treasury regulations provide that recapture is determined at the partner level (subject to certain anti-abuse provisions). Where only a portion of recapture property is disposed of, any IDC related to the entire property
is recaptured to the extent of the gain realized on the portion of the property sold. In the case of the disposition of an undivided interest in a property (as opposed to the disposition of a portion of the property), a proportionate part of the IDC
with respect to the property is treated as allocable to the transferred undivided interest to the extent of any realized gain. 
  
 Depletion Deductions 
  
 The owner of an economic interest in an oil and gas property is entitled to claim the greater of percentage depletion or cost depletion with respect to
oil and gas properties which qualify for such depletion methods. In the case of partnerships, the depletion allowance must be computed separately by each partner and not by the partnership. For properties placed in service after 1986, depletion
deductions, to the extent they reduce basis in an oil and gas property, are subject to recapture under Code section 1254. 
  

 54 

 Cost depletion for any year is determined by multiplying the number of units (e.g., barrels of oil or Mcf
of gas) sold during the year by a fraction, the numerator of which is the cost or other basis of the mineral interest and the denominator of which is total reserves available at the beginning of the period. In no event can the cost depletion exceed
the adjusted basis of the property to which it relates. 
  
 Percentage depletion is a statutory allowance pursuant to which a deduction currently equal to 15% of the taxpayer’s gross income from each property is allowed in any taxable year, not to exceed 100% of the taxpayer’s taxable
income from the property (computed without the allowance for depletion) with the aggregate deduction limited to 65% of the taxpayer’s taxable income for the year (computed without regard to percentage depletion and net operating loss and
capital loss carrybacks). The percentage depletion deduction rate will vary with the price of oil, but the rate will not be less than 15%. A percentage depletion deduction that is disallowed in a year due to the 65% of taxable income limitation may
be carried forward and allowed as a deduction for a subsequent year, subject to the 65% limitation in that subsequent year. Percentage depletion deductions reduce the taxpayer’s adjusted basis in the property. However, unlike cost depletion,
percentage depletion deductions are not limited to the adjusted basis of the property; the percentage depletion amount continues to be allowable as a deduction after the adjusted basis has been reduced to zero. 
  
 The availability of depletion, whether cost or percentage, will be determined
separately by each Partner. Each Partner must separately keep records of his share of the adjusted basis in an oil or gas property, adjust such share of the adjusted basis for any depletion taken on such property, and use such adjusted basis each
year in the computation of his cost depletion or in the computation of his gain or loss on the disposition of such property. These requirements may place an administrative burden on a Partner. 
  
 Depreciation Deductions 
  
 The Partnership will claim depreciation, cost recovery, and amortization
deductions with respect to its basis in Partnership Property as permitted by the Code. 
  
 Transaction Fees 
  
 The Partnership may
classify a portion of the fees or expense reimbursements to be paid to third parties and to the General Partner as expenses which are deductible as organizational expenses or otherwise. There is no assurance that the Service will allow the
deductibility of such expenses and Conner & Winters expresses no opinion with respect to the allocation of such fees or reimbursements to deductible and nondeductible items. 
  
 Generally, expenditures made in connection with the creation of, and with sales of interests in, a partnership will fit
within one of several categories. 
  
 A partnership may elect to
amortize and deduct its organizational expenses ratably over a period of not less than 60 months commencing with the month the partnership begins business. Examples of organizational expenses are legal fees for services incident to the organization
of the partnership, such as negotiation and preparation of a partnership agreement, accounting fees for services incident to the organization of the partnership, and filing fees. 
  
 No deduction is allowable for “syndication expenses,” examples of which include brokerage fees, registration fees,
legal fees of the underwriter or placement agent and the issuer (general partners or the partnership) for securities advice and for advice pertaining to the adequacy of tax disclosures in the offering or private placement memorandum for securities
law purposes, printing costs, and other selling or promotional material. These costs must be capitalized. Payments for services performed in connection with the acquisition of capital assets must be amortized over the useful life of such assets.

  
 No deduction is allowable with respect to “start-up
expenditures,” although such expenditures may be capitalized and amortized over a period of not less than 60 months. 
  
 The Partnership intends to make overhead reimbursement payments to the General Partner, as described in greater detail in the Memorandum. To be
deductible, payments to a partner must be for services rendered by the partner other than in his or its capacity as a partner or for compensation determined without regard to partnership income. Payments which are not deductible because they fail to
meet this test may be treated as special allocations of income to the recipient partner and thereby decrease the net loss, or increase the net income 

  

 55 

 
among all partners. If the Service were to successfully challenge the General Partner’s allocations, a Partner’s taxable income could be increased,
thereby resulting in increased taxes and in potential liability for interest and penalties. 
  
 Basis and At Risk Limitations 
  
 A Partner’s share of Partnership losses will be allowed as a deduction by the Partner only to the extent of the aggregate amount with respect to which the taxpayer-Partner is “at risk” for the
Partnership’s activity at the close of the taxable year. Any such loss disallowed by the “at risk” limitation shall be treated as a deduction allocable to the activity in the first succeeding taxable year. 
  
 The Code provides that a taxpayer must recognize taxable income to the extent
that his or her “at risk” amount is reduced below zero. This “recaptured” income is limited to the sum of the loss deductions previously allowed to the taxpayer, less any amounts previously recaptured. A taxpayer may be allowed a
deduction for the recaptured amounts included in his taxable income if and when he increases his amount “at risk” in a subsequent taxable year. 
  
 The Limited Partners will purchase Units by tendering cash to the Partnership. To the extent the cash contributed constitutes the “personal
funds” of the Partners, the Partners should be considered at risk with respect to those amounts. If the cash contributed constitutes “personal funds,” in the opinion of Conner & Winters, neither the at risk rules nor the adjusted
basis rules will limit the deductibility of losses generated from the Partnership and allocated to a Limited Partner, to the extent of such Limited Partner’s cash contributions. In no event, however, may a Partner deduct his distributive share
of partnership loss where such share exceeds the Partner’s tax basis in the Partnership. 
  
 Passive Loss Limitations 
  
 Introduction. The deductibility of losses generated from passive activities will be limited for certain taxpayers. The passive activity loss limitations apply to individuals, estates, trusts, and personal service corporations
as well as, to a lesser extent, closely held C corporations. 
  
 The definition of a “passive activity” generally encompasses all rental activities as well as all activities with respect to which the taxpayer does not “materially participate.” A taxpayer will be considered as
materially participating in a venture only if the taxpayer is involved in the operations of the activity on a “regular, continuous, and substantial” basis. In addition, no limited partnership interest will be treated as an interest with
respect to which a taxpayer materially participates. 
  
 Passive
activity losses (“PALs”) of a taxpayer are the amounts of such taxpayer’s losses from passive activities for a taxable year. Individuals and personal service corporations are entitled to deduct PALs only to the extent of their
passive income whereas closely held C corporations (other than personal service corporations) can offset PALs against both passive and net active income, but not against portfolio (dividends, interest, etc.) income. In calculating passive income and
loss, however, all passive activities of the taxpayer are aggregated. PALs disallowed as a result of the above rules will be suspended and can be carried forward indefinitely to offset future passive (or passive and active, in the case of a closely
held C corporation) income. 
  
 Upon a taxpayer’s disposition
of his entire interest in a passive activity in a fully taxable transaction not involving a related party, any passive loss of such taxpayer that was suspended by the provisions of the passive activity loss rules is deductible against either passive
or non-passive income. 
  
 Limited Partner
Interests. Most Limited Partners’ distributive shares of the Partnership’s losses will be treated as PALs, the availability of which will be limited in each case to the individual Partner’s passive income in all passive
activities in which the Limited Partner has an interest. If a Limited Partner does not have sufficient passive income to utilize the PALs, the disallowed PALs will be suspended and may be carried forward to be deducted against passive income arising
in future years. Further, upon the disposition by a Limited Partner of his entire interest in the Partnership to an unrelated party in a fully taxable transaction, such suspended losses will be available, as described above. 
  

 56 

 Gain or Loss on Sale of Property or Units 
  
 In the event some or all of the property of the Partnership is sold, or upon sale of a Unit, a Limited Partner will realize
gain to the extent the amount realized exceeds his or her basis in the Partnership. In such case, there may be recapture, as ordinary income, of IDCs and depletion previously allocated to such Limited Partner. If the gain realized exceeds the amount
of the recapture income, the Limited Partner will recognize capital gains for the balance. 
  
 It is possible that a Limited Partner will be required to recognize ordinary income pursuant to the recapture rules in excess of the taxable income on the disposition transaction or in a situation where the
disposition transaction resulted in a taxable loss. To balance the excess income, the Limited Partner would recognize a capital loss for the difference between the gain and the income. Depending on a Limited Partner’s particular tax situation,
some or all of this loss might be deferred to future years, resulting in a greater tax liability in the year in which the sale was made and a reduced future tax liability. 
  
 Any partner who sells or exchanges interests in a partnership must generally notify the partnership in writing within 30
days of such transaction in accordance with Regulations and must attach a statement to his tax return reflecting certain facts regarding the sale or exchange. The notice must include names, addresses, and taxpayer identification numbers (if known)
of the transferor and transferee and the date of the exchange. The partnership also is required to provide copies to the transferor and the transferee of information it is required to provide to the Service in connection with such a transfer.

  
 Partnership Distributions 
  
 Under the Code, any increase in a partner’s share of partnership
liabilities, or any increase in such partner’s individual liabilities by reason of an assumption by him or her of partnership liabilities is considered to be a contribution of money by the partner to the partnership. Similarly, any decrease in
a partner’s share of partnership liabilities or any decrease in such partner’s individual liabilities by reason of the partnership’s assumption of such individual liabilities will be considered as a distribution, a constructive
distribution, of money to the partner by the partnership. 
  
 A
Partner’s adjusted basis in his or her Units will initially consist of the cash he or she contributes to the Partnership. His or her basis will be increased by his or her share of Partnership income and decreased by his or her share of
Partnership losses and distributions. To the extent that actual or constructive distributions are in excess of a Partner’s adjusted basis in his or her Partnership interest (after adjustment for contributions and his or her share of income and
losses of the Partnership), that excess will generally be treated as gain from the sale of a capital asset. In addition, gain could be recognized to a distributee partner upon the disproportionate distribution to a partner of unrealized receivables
or substantially appreciated inventory. The Partnership Agreement prohibits distributions to a Limited Partner to the extent such distribution would create or increase a deficit in a Limited Partner’s Capital Account. 
  
 Partnership Allocations 
  
 The Partners’ distributive shares of partnership income, gain, loss,
and deduction should be determined and allocated substantially in accordance with the terms of the Partnership Agreement. 
  
 The Service could contend that the allocations contained in the Partnership Agreement do not have substantial economic effect or are not in accordance
with the Partners’ interests in the Partnership and may seek to reallocate these items in a manner that will increase the income or gain or decrease the deductions allocable to a Partner. 
  
 Administrative Matters 
  
 Returns and Audits. While no federal income tax is required to
be paid by an organization classified as a partnership for federal income tax purposes, a partnership must file federal income tax information returns which are subject to audit by the Service. Any such audit may lead to adjustments, in which event
the Limited Partners may be required to file amended personal federal income tax returns. Any such audit may also lead to an audit of a Limited Partner’s individual tax return and adjustments to items unrelated to an investment in Units.

  

 57 

 For purposes of reporting, audit, and assessment of additional federal income tax, the tax treatment of
“partnership items” is determined at the partnership level. Partnership items will include those items that the Regulations provide are more appropriately determined at the partnership level than the partner level. The Service generally
cannot initiate deficiency proceedings against an individual partner with respect to partnership items without first conducting an administrative proceeding at the partnership level as to the correctness of the partnership’s treatment of the
item. An individual partner may not file suit for a credit or a refund arising out of a partnership item without first filing a request for an administrative proceeding by the Service at the partnership level. Individual partners are entitled to
notice of such administrative proceedings and decisions therein, except in the case of partners with less than 1% profits interest in a partnership having more than 100 partners. If a group of partners having an aggregate profits interest of 5% or
more in such a partnership so requests, however, the Service also must mail notice to a partner appointed by that group to receive notice. All partners, whether or not entitled to notice, are entitled to participate in the administrative proceedings
at the partnership level, although the Partnership Agreement provides for waiver of certain of these rights by the Limited Partners. All Partners, including those not entitled to notice, may be bound by a settlement reached by the Partnership’s
representative, the “tax matters partner,” which will be Unit Petroleum Company. If a proposed tax deficiency is contested in any court by any Partner or by the General Partner, all Partners may be deemed parties to such litigation and
bound by the result reached therein. 
  
 Consistency
Requirements. A partner must generally treat partnership items on his or her federal income tax returns consistently with the treatment of such items on the partnership information return unless he or she files a statement with the Service
identifying the inconsistency or otherwise satisfies the requirements for waiver of the consistency requirement. Failure to satisfy this requirement will result in an adjustment to conform the partner’s treatment of the item with the treatment
of the item on the partnership return. Intentional or negligent disregard of the consistency requirement may subject a partner to substantial penalties. 
  
 Compliance Provisions. Taxpayers are subject to several penalties and other provisions that encourage compliance with the federal income tax
laws, including an accuracy-related penalty in an amount equal to 20% of the portion of an underpayment of tax caused by negligence, intentional disregard of rules or regulations or any “substantial understatement” of income tax. A
“substantial understatement” of tax is an understatement of income tax that exceeds the greater of (a) 10% of the tax required to be shown on the return (the correct tax), or (b) $5,000 ($10,000 in the case of a corporation other than an S
corporation or personal holding corporation). 
  
 Except in the
case of understatements attributable to “tax shelter” items, an item of understatement may not give rise to the penalty if (a) there is or was “substantial authority” for the taxpayer’s treatment of the item or (b) all facts
relevant to the tax treatment of the item are disclosed on the return or on a statement attached to the return, and there is a reasonable basis for the tax treatment of such item by the taxpayer. In the case of partnerships, the disclosure is to be
made on the return of the partnership. Under the applicable Regulations, however, an individual partner may make adequate disclosure with respect to partnership items if certain conditions are met. 
  
 In the case of understatements attributable to “tax shelter” items,
the substantial understatement penalty may be avoided only if the taxpayer establishes that, in addition to having substantial authority for his or her position, he or she reasonably believed the treatment claimed was more likely than not the proper
treatment of the item. A “tax shelter” item is one that arises from a partnership (or other form of investment) the principal purpose of which is the avoidance or evasion of federal income tax. 
  
 Based on the definition of a “tax shelter” in the Regulations,
performance of previous partnerships, and the planned activities of the Partnership, the General Partner does not believe that the Partnership will qualify as a “tax shelter” under the Code, and will not register it as such. 
  
 Accounting Methods and Periods 
  
 The Partnership will use the accrual method of accounting and will select
the calendar year as its taxable year. 
  

 58 

 State and Local Taxes 
  
 The opinions expressed herein are limited to issues of federal income tax law and do not address issues of state or local
law. Prospective investors are urged to consult their tax advisors regarding the impact of state and local laws on an investment in the Partnership. 
  
 Individual Tax Advice Should Be Sought 
  
 The foregoing is only a summary of the material tax considerations that may affect an investor’s decision regarding the purchase of Units. The tax
considerations attendant to an investment in a Partnership are complex and vary with individual circumstances. Each prospective investor should review such tax consequences with his tax advisor. 
  
 COMPETITION, MARKETS AND REGULATION 
  
 The oil and gas industry is highly competitive in all its phases. The
Partnership will encounter strong competition from both major independent oil companies and individuals, many of which possess substantial financial resources, in acquiring economically desirable prospects and equipment and labor to operate and
maintain Partnership Properties. There are likewise numerous companies and individuals engaged in the organization and conduct of oil and gas drilling programs and there is a high degree of competition among such companies and individuals in the
offering of their programs. 
  
 Marketing of Production 

 
 The availability of a ready market for any oil and gas produced from
Partnership Wells will depend upon numerous factors beyond the control of the Partnership, including the extent of domestic production and importation of oil and gas, the proximity of Partnership Wells to gas pipelines and the capacity of such gas
pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining and transportation, general national and worldwide economic conditions, and the pricing, use and allocation of oil and gas
and their substitute fuels. 
  
 The demand for gas decreased
significantly in the 1980s due to economic conditions, conservation and other factors. As a result of such reduced demand and other factors, including the Power Plant and Industrial Fuel Use Act (the “Fuel Use Act”) which related to
the use of oil and gas in the United States in certain fuel burning installations, many pipeline companies began purchasing gas on terms which were not as favorable to sellers as terms governing purchases of gas prior thereto. Spot market gas prices
declined generally during that period. While the Fuel Use Act has been repealed and the markets for gas have improved significantly recently, there can be no assurance that such improvement will continue. As a result, it is possible that there may
be significant delays in selling any gas from Partnership Properties. 
  
 In the event the Partnership acquires an interest in a gas well or completes a productive gas well, or a well that produces both oil and gas, the well may be shut in for a substantial period of time for lack of a market if the well is in an
area distant from existing gas pipelines. The well may remain shut in until such time as a gas pipeline, with available capacity, is extended to such an area or until such time as sufficient wells are drilled to establish adequate reserves which
would justify the construction of a gas pipeline, processing facilities, if necessary, and a transmission system. 
  
 The worldwide supply of oil has been largely dependent upon rates of production of foreign reserves. Although in recent years the demand for oil has
slightly increased in this country, imports of foreign oil continue to increase. Consequently, historically the prices for domestic oil production have generally remained low. Future domestic oil prices will depend largely upon the actions of
foreign producers with respect to rates of production and it is virtually impossible to predict what actions those producers will take in the future. Prices may also be affected by political and other factors relating to the Middle East. As a
result, it is possible that prices for oil, if any, produced from a Partnership Well will be lower than those currently available or projected at the time the interest therein is acquired. In view of the many uncertainties affecting the supply and
demand for crude oil and natural gas, and the change in the makeup of the Congress of the United States and the resulting potential for a different focus for the United States energy policy, the General Partner is unable to predict what future gas
and oil prices will be. 
  

 59 

 Regulation of Partnership Operations 
  
 Production of any oil and gas found by the Partnership will be affected by state and federal regulations. All states in
which the Partnership intends to conduct activities have statutory provisions regulating the production and sale of oil and gas. Such statutes, and the regulations promulgated in connection therewith, generally are intended to prevent waste of oil
and gas and to protect correlative rights and the opportunities to produce oil and gas as between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of
production to each well or proration unit. Pertinent state and federal statutes and regulations also extend to the prevention and clean-up of pollution. These laws and regulations are subject to change and no predictions can be made as to what
changes may be made or the effect of such changes on the Partnership’s operations. 
  
 Under the laws and administrative regulations of the State of Oklahoma regarding forced pooling, owners of oil and gas leases or unleased mineral interests may be required to elect to participate in the drilling of a
well with other fractional undivided interest owners within an established spacing unit or to sell or farm out their interest therein. The terms of any such sale or farm-out are generally those determined by the Oklahoma Corporation Commission to be
equal to the most favorable terms then available in the area in arm’s length transactions although there can be no assurance that this will be the case. In addition, if properties become the subject of a forced pooling order, drilling
operations may have to be undertaken at a time or with other parties which the General Partner feels may not be in the best interest of the Partnership. In such event, the Partnership may have to farm out or assign its interest in such properties.
In addition, if a property which might otherwise be acquired by the Partnership becomes subject to such an order, it may become unavailable to the Partnership. Finally, as a result of forced pooling proceedings involving a Partnership Property, the
Partnership may acquire a larger than anticipated interest in such property, thereby increasing its share of the costs of operations to be conducted. 
  
 Natural Gas Price Regulation 
  
 Partnership Revenues are likely to be dependent on the sale and transportation of natural gas that may be subject to regulation by the Federal Energy
Regulatory Commission (“FERC”). Historically the sale of natural gas has been regulated by the FERC under the Natural Gas Act of 1938 (“NGA”) and/or the Natural Gas Policy Act of 1978 (“NGPA”).
Under the NGPA, natural gas is divided into numerous, complex categories based on, among other things, when, where and how deep the gas well was drilled and whether the gas was committed to interstate or intrastate commerce on the day before the
date of enactment of the statute. These categories determine whether the natural gas remains subject to non-price regulation under the NGA and/or to maximum price restrictions under the NGPA. In addition to setting ceiling prices for natural gas,
FERC approval is required for both the commencement and abandonment of sales of certain categories of gas in interstate commerce for resale and for the transportation of natural gas in interstate commerce. FERC has general investigatory and other
powers, including limited authority to set aside or modify terms of gas purchase contracts subject to its jurisdiction. Price and non-price regulation of natural gas produced from most wells drilled after 1978 has terminated. That gas may be sold
without prior regulatory approval and at whatever price the market will bear. 
  
 On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 became effective. Consequently, due to this statutory deregulation and FERC’s issuance of Order No. 547 discussed below, as of January 7, 1993 the
price of virtually all gas produced by producers not affiliated with interstate pipelines has been deregulated by FERC. 
  
 Market determined prices for deregulated categories of natural gas fluctuate in response to market pressures which currently favor purchasers and disfavor
producers. As a result of the deregulation of a greater proportion of the domestic United States gas market and an increased availability of natural gas transportation, a competitive trading market for gas has developed. For several reasons the
supply of gas has exceeded demand. The General Partner cannot reliably predict at this time whether such supply/demand imbalance will improve or worsen from a producer’s viewpoint. 
  

 60 

 During the past several years, FERC has adopted several regulations designed to create a more
competitive, less regulated market for natural gas. These regulations have materially affected the market for natural gas. 
  
 FERC’s initial major initiative was adoption of its “open-access transportation program,” through Order No.s 436 and 500. Regulation of
Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 Fed. Reg. 42,408 (October 18, 1985), vacated and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006
(1988), readopted on an interim basis, Order No. 500, 52 Fed. Reg. 30,344 (Aug. 14, 1987), remanded, American Gas Association v. FERC, 888 F.2d 136 (D.C. Cir. 1989), readopted, Order No. 500-H, 54 Fed. Reg. 52,344 (Dec.
21, 1989), reh’g granted in part and denied in part, Order No. 500-I, 55 Red. Reg. 6605 (Feb. 26, 1990), aff’d in part and remanded in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir. 1990), cert.
denied, 111 S. Ct. 957 (1991). Order 436 implemented three key requirements: (1) jurisdictional pipelines were required to permit their firm sales customers to convert their firm sales entitlements to a volumetrically equivalent amount of firm
transportation service over a five-year period; (2) jurisdictional pipelines were required to offer their open-access transportation services without discrimination or preference; and (3) jurisdictional pipelines were required to design maximum
rates to ration capacity during peak periods and to maximize throughput for firm service during off-peak periods and for interruptible service during all periods. The availability of transportation under Order 500 greatly expanded the free trading
market for natural gas, including the establishment of an active and viable spot market. 
  
 Subsequently, in Order 636 the FERC focused on whether the resulting regulatory structure provided all gas sellers with the same regulatory opportunity to compete for gas purchasers. It decided that the form of
bundled pipeline services (gas sales and transportation) was unduly discriminatory and anticompetitive. Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines
After Wellhead Decontrol, Order No. 636, 57 Fed. Reg. 13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at 30,406; Regulations of Natural Gas Pipelines After Partial Wellhead Decontrol, and Order Denying Rehearing in
Part, Granting Rehearing in Part, and Clarifying Order No. 636, Order No. 636-A, 57 Fed. Reg. 36,128 (Aug. 12, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,950; Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol;
Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol; Order Denying Rehearing and Clarifying Order Nos. 636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec. 8, 1992). 
  
 Among other things, Order 636 required each interstate pipeline company to “unbundle” its traditional wholesale
services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales services) and to adopt a
new rate making methodology (Straight Fixed Variable) to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it will do so in direct competition with
all other sellers pursuant to private contracts; however, pipeline companies have or will become “transporters only.” Order 636 also allows pipeline companies to act as agents for their customers in arranging the transportation of gas
purchased from any supplier, including the pipeline itself, and to charge a negotiated fee for such agency services. The FERC required each pipeline company to develop the specific terms of service in individual proceedings and to submit for
approval by FERC a compliance filing which set forth the pipeline company’s new, detailed procedures. 
  
 In response to a Court remand, on February 27, 1997 FERC issued its final rule further revising Order 636. Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation Under Part 284 and Regulation of National Pipelines After Partial Wellhead Decontrol, 62 Fed. Reg. 10204 (Mar. 6, 1997). It modified its regulation by (i) changing the selection of a twenty-year
matching term for the right of first refusal and instead adopting a five-year matching term and (ii) reversing the requirement that pipelines allocate 10% of GSR costs to interruptible customers and requiring that pipelines propose the percentage
that interruptible customers will bear based on the individual circumstances present on each pipeline. Most of the individual pipeline restructurings arising from Order 636 have been completed. 
  
 In essence, the goal of Order 636 is to make a pipeline’s position as
gas merchant indistinguishable from that of a non-pipeline supplier. It, therefore, pushes the point of sale of gas by pipelines upstream, perhaps all the way to the wellhead. Order 636 also requires pipelines to give firm transportation customers
flexibility with 

  

 61 

 
respect to receipt and delivery points (except that a firm shipper’s choice of delivery point cannot be downstream of the existing primary delivery
point) and to allow “no-notice” service (which means that gas is available not only simultaneously but also without prior nomination, with the only limitation being the customer’s daily contract demand) if the pipeline offered
no-notice city-gate sales service on May 18, 1992. Thus, this separation of pipelines’ sales and transportation allows non-pipeline sellers to acquire firm downstream transportation rights and thus to offer buyers what is effectively a bundled
city-gate sales service and it permits each customer to assemble a package of services that serves its individual requirements. But it also makes more difficult the coordination of gas supply and transportation. 
  
 The results of these changes could increase the marketability of natural gas
and place the burden of obtaining supplies of natural gas for local distribution systems directly on distributors who would no longer be able to rely on the aggregation of supplies by the interstate pipelines. Such distributors may return to longer
term contracts with suppliers who can assure a secure supply of natural gas. A return to longer term contracts and the attendant decrease in gas available for the spot market could improve gas prices. The primary beneficiaries of these changes
should be gas marketers and the producers who are able to demonstrate the availability of an assured long-term supply of natural gas to local distribution purchasers and to large end users. However, due to the still evolutionary nature of Order 636
and its implementation, it is not possible at this time to project the impact Order 636 will have on the Partnership’s ability to sell gas directly into gas markets previously served by the gas pipelines. 
  
 As a corollary to Order 636, FERC issued Order 547, which is a blanket
certificate of public convenience and necessity pursuant to Section 7 of the NGA that authorizes any person who is not an interstate pipeline or an affiliate thereof to make sales for resale at negotiated rates in interstate commerce of any category
of gas that is subject to the Commission’s NGA jurisdiction. (There are certain requirements which must be met before an affiliated marketer of an interstate pipeline can avail itself of this certification.) Regulations Governing Blanket
Marketer Sales Certificates, Order No. 547, 57 Fed. Reg. 57,952 (Dec. 8, 1992) (to be codified at 18 C.F.R. Sections 284.401 - .402). The blanket certificates were effective January 7, 1993, and do not require any further application by a person.
The goal of Order 457, in conjunction with Orders 636, 636-A and 636-B, is to provide all merchants of natural gas a “level playing field” so that gas merchants who are not interstate pipelines are on an equal footing with interstate
pipeline merchants who are afforded blanket sales certificates pursuant to Order 636. 
  
 The FERC has also begun to allow individual companies to depart from cost-of-service regulation and set market-based rates if they can show they lack significant market power or have mitigated market power.
See, e.g., Richmond Gas Storage Systems, 59 FERC Paragraph 61,316 (1992); El Paso Natural Gas Company, 54 FERC Paragraph 61,316, reh’g granted and denied in part, 56 FERC Paragraph 61,290 (1990);
Transcontinental Gas Pipe Line Corp., 53 FERC Paragraph 61,446, reh’g granted and denied in part, 57 FERC Paragraph 61,345 (1991). Since the FERC has stated that “[w]here companies have market power, market-based rates are
not appropriate,” in order to “enhance productive efficiency in non-competitive markets,” the FERC issued a rule allowing pipelines (and electric utilities) “to propose incentive rate mechanisms as alternatives to traditional
cost-of-service regulations.” Incentive Ratemaking for Interstate Natural Gas Pipelines, Oil Pipelines, and Electric Utilities; Policy Statement on Incentive Regulation, 57 Fed. Reg. 55,231 (Nov. 24, 1992). The FERC has established five
specific regulatory standards for implementing specific incentive mechanisms: they should (1) be prospective, (2) be voluntary, (3) be understandable, (4) result in quantifiable benefits to consumers including an upper limit on the risk to consumers
that the incentive rates would be higher than rates they would have paid under traditional regulation, and (5) demonstrate how they maintain or enhance incentives to improve the quality of service. 
  
 Other regulatory actions have included elimination of minimum take and
minimum bill provisions of pipeline sales tariffs (Order 380) and authorization of automatic abandonment authority upon expiration or termination of the underlying contracts (Order 490). FERC has also provided several forms of “blanket”
certificates authorizing sales of gas with pregranted abandonment. 
  
 In addition, in Order 451, FERC established an alternative maximum lawful price for certain NGPA Section 104 and 106 gas produced from wells drilled prior to 1975 (so-called “old gas”) which otherwise would be subject to lower
ceiling prices. FERC provided, however, that the higher price could be collected only where the parties amended the contract or pursuant to complicated “good faith negotiation” rules which permit 

  

 62 

 
purchasers facing requests for increased prices to seek reduction of certain higher prices and authorize abandonment of both the higher cost and lower cost
supplies if agreement cannot be reached. After the Fifth Circuit vacated Order 451 as an invalid exercise of FERC’s authority, the United States Supreme Court reversed that decision and upheld the entirety of Order 451. 
  
 The issuance of Order 636 and its future interpretation, as well as the
future interpretation and application by FERC of all of the above rules and its broad authority, or of the state and local regulations by the relevant agencies, could affect the terms and availability of transportation services for transportation of
natural gas to customers and the prices at which gas can be sold on behalf of the Partnership. For instance, as a result of Order 636, many interstate pipeline companies have divested their gathering systems, either to unregulated affiliates or to
third persons, a practice which could result in separate, and higher, rates for gathering a producer’s natural gas. In proceedings during mid and late 1994 allowing various interstate natural gas companies’ spindowns or spinoffs of
gathering facilities, the FERC held that, except in limited circumstances of abuse, it generally lacks jurisdiction over a pipeline’s gathering affiliates, which neither transport natural gas in interstate commerce nor sell gas in interstate
commerce for resale. However, pipelines spinning down gathering systems have to include two Order No. 497 standards of conduct in their tariffs: nondiscriminatory access to transportation for all sources of supply and no tying of pipeline
transportation service to any service by the pipeline’s gathering affiliate. In addition, if unable to reach a mutually acceptable gathering contract with a present user of the gathering facilities, the FERC required that the pipeline must
offer a two-year “default contract” to existing users of the gathering facilities. However, on appeal, while the United States Court of Appeals for the District of Columbia upheld the FERC’s allowing the spinning down of gathering
facilities to a non-regulated affiliate, in Conoco Inc. v. FERC, 90 F.3d 536, 552-53 (D.C. Cir. 1996) the D.C. Circuit remanded the FERC’s default contract mechanism. On February 18, 1997 the United States Supreme Court denied a petition
to review the D. C. Circuit’s decision. As a result of FERC’s action, some states have enacted or are considering statutory and/or regulatory provisions to regulate gathering systems. Consequently, the General Partner cannot reliably
predict at this time how regulation will ultimately impact Partnership Revenue. 
  
 Oil Price Regulation 
  
 With respect to
oil pipeline rates subject to the FERC’s jurisdiction under the Interstate Commerce Act, in October 1993 the FERC issued Order 561 to implement the requirements of Title XVIII of the Energy Policy Act of 1992. Order 561 established an indexing
system, effective January 1, 1995, under which many oil pipelines are able to readily change their rates to track changes in the Producer Price Index for Finished Goods (PPI-FG), minus one percent. This index established ceiling levels for rates.
Order 561 also permits cost-of-service proceedings to establish just and reasonable rates. The Order does not alter the right of a pipeline to seek FERC authorization to charge market rates. However, until the FERC makes the finding that the
pipeline does not exercise significant market power, the pipeline’s rates cannot exceed the applicable index ceiling level or a level justified by the pipeline’s cost of service. 
  
 State Regulation of Oil and Gas Production 
  
 Most states in which the Partnership may conduct oil and gas activities
regulate the production and sale of oil and natural gas. Those states generally impose requirements or restrictions for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste
of oil and gas resources. In addition, most states regulate the rate of production and may establish maximum daily production allowable from both oil and gas wells on a market demand or conservation basis. Until recently there has been no limit on
allowable daily production on the basis of market demand, although at some locations production continues to be regulated for conservation or market purposes. In 1992 Oklahoma and Texas imposed additional limitations on gas production to more
closely track market demand. The General Partner cannot predict whether any state regulatory agency may issue additional allowable reductions which may adversely affect the Partnership’s ability to produce its gas reserves. 
  
 Legislative and Regulatory Production and Pricing Proposals 
  
 A number of legislative and regulatory proposals continually are advanced
which, if put into effect, could have an impact on the petroleum industry. The various proposals involve, among other things, an oil import fee, restructuring how oil pipeline rates are determined and implemented reducing production allowables,
providing 

  

 63 

 
purchasers with “market-out” options in existing and future gas purchase contracts, eliminating or limiting the operation of take-or-pay clauses,
eliminating or limiting the operation of “indefinite price escalator clauses” (e.g., pricing provisions which allow prices to escalate by means of reference to prices being paid by other purchasers of natural gas or prices for competing
fuels), and state regulation of gathering systems. Proposals concerning these and other matters have been and will be made by members of the President’s office, Congress, regulatory agencies and special interest groups. The General Partner
cannot predict what legislation or regulatory changes, if any, may result from such proposals or any effect therefrom on the Partnership. 
  
 The effect of these regulations could be to decrease allowable production on Partnership Properties and thereby to decrease Partnership Revenues. However,
by decreasing the amount of natural gas available in the market, such regulations could also have the effect of increasing prices of natural gas, although there can be no assurance that any such increase will occur. There can also be no assurance
that the proposed regulations described above will be adopted or that they will be adopted upon the terms set forth above. Additionally, such proposals, if adopted, are likely to be challenged in the courts and there can be no assurance as to the
outcome of any such challenge. 
  
 Production and Environmental Regulation

  
 Certain states in which the Partnership may drill and
own productive properties control production from wells through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise limiting the rate of allowable production.

  
 In addition, the federal government and various state
governments have adopted laws and regulations regarding protection of the environment. These laws and regulations may require the acquisition of a permit before or after drilling commences, impose requirements that increase the cost of operations,
prohibit drilling activities on certain lands lying within wilderness areas or other environmentally sensitive areas and impose substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or
on submerged lands. 
  
 A past, present, or future release or
threatened release of a hazardous substance into the air, water, or ground by the Partnership or as a result of disposal practices may subject the Partnership to liability under the Comprehensive Environmental Response, Compensation and Liability
Act, as amended (“CERCLA”), the Resource Conservation Recovery Act (“RCRA”), the Clean Water Act, and/or similar state laws, and any regulations promulgated pursuant thereto. Under CERCLA and similar laws, the
Partnership may be fully liable for the cleanup costs of a release of hazardous substances even though it contributed to only part of the release. While liability under CERCLA and similar laws may be limited under certain circumstances, typically
the limits are so high that the maximum liability would likely have a significant adverse effect on the Partnership. In certain circumstances, the Partnership may have liability for releases of hazardous substances by previous owners of Partnership
Properties. Additionally, the discharge or substantial threat of a discharge of oil by the Partnership into United States waters or onto an adjoining shoreline may subject the Partnership to liability under the Oil Pollution Act of 1990 and similar
state laws. While liability under the Oil Pollution Act of 1990 is limited under certain circumstances, the maximum liability under those limits would still likely have a significant adverse effect on the Partnership. The Partnership’s
operations generally will be covered by the insurance carried by the General Partner or UNIT, if any. However, there can be no assurance that such insurance coverage will always be in force or that, if in force, it will adequately cover any losses
or liability the Partnership may incur. 
  
 Violation of
environmental legislation and regulations may result in the imposition of fines or civil or criminal penalties and, in certain circumstances, the entry of an order for the removal, remediation and abatement of the conditions, or suspension of the
activities, giving rise to the violation. The General Partner believes that the Partnership will comply with all orders and regulations applicable to its operations. However, in view of the many uncertainties with respect to the current controls,
including their duration and possible modification, the General Partner cannot predict the overall effect of such controls on such operations. Similarly, the General Partner cannot predict what future environmental laws may be enacted or regulations
may be promulgated and what, if any, impact they would have on operations or Partnership Revenue. 
  

 64 

 SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT 
  
 The business and affairs of the Partnership and the respective rights and
obligations of the Partners will be governed by the Agreement. The following is a summary of certain pertinent provisions of the Agreement which have not been as fully discussed elsewhere in this Memorandum but does not purport to be a complete
description of all relevant terms and provisions of the Agreement and is qualified in its entirety by express reference to the Agreement. Each prospective subscriber should carefully review the entire Agreement. 
  
 Partnership Distributions 
  
 The General Partner will make quarterly determinations of the
Partnership’s cash position. If it determines that excess cash is available for distribution, it will be distributed to the Partners in the same proportions that Partnership Revenue has been allocated to them after giving effect to previous
distributions and to portions of such revenues theretofore used or expected to be thereafter used to pay costs incurred in conducting Partnership operations or to repay Partnership borrowings. It is expected that no cash distributions will be made
earlier than the first quarter of 2006. Distributions of cash determined by the General Partner to be available therefore will be made to the Limited Partners quarterly and to the General Partner at any time. All Partnership funds distributed to the
Limited Partners shall be distributed to the persons who were record holders of Units on the day on which the distribution is made. Thus, regardless of when an assignment of Units is made, any distribution with respect to the Units which are
assigned will be made entirely to the assignee without regard to the period of time prior to the date of such assignment that the assignee holds the Units. 
  
 The Partnership will terminate automatically on December 31, 2035 unless prior thereto the General Partner or Limited Partners holding a majority of the
outstanding Units elect to terminate the Partnership as of an earlier date. Upon termination of the Partnership, the debts, liabilities and obligations of the Partnership will be paid and the Partnership’s oil and gas properties and any
tangible equipment, materials or other personal property may be sold for cash. The cash received will be used to make certain adjusting payments to the Partners (see “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Termination”). Any
remaining cash and properties will then be distributed to the Partners in proportion to and to the extent of any remaining balances in the Partners’ capital accounts and then in undivided percentage interests to the Partners in the same
proportions that Partnership Revenues are being shared at the time of such termination (see “SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT — Termination”). 
  
 Deposit and Use of Funds 
  
 Until required in the conduct of the Partnership’s business, Partnership funds, including, but not limited to, the Capital Contributions, Partnership
Revenue and proceeds of borrowings by the Partnership, will be deposited, with or without interest, in one or more bank accounts of the Partnership in a bank or banks to be selected by the General Partner or invested in short-term United States
government securities, money market funds, bank certificates of deposit or commercial paper rated as “A1” or “P1” as the General Partner, in its sole discretion, deems advisable. Any interest or other income generated by such
deposits or investments will be for the Partnership’s account. Except for Capital Contributions, Partnership funds from any of the various sources mentioned above may be commingled with funds of the General Partner and may be used, expended and
distributed as authorized by the terms and provisions of the Agreement. The General Partner will be entitled to prompt reimbursement of expenses it incurs on behalf of the Partnership. 
  
 Power and Authority 
  
 In managing the business and affairs of the Partnership, the General Partner is authorized to take such action as it considers appropriate and in the best
interests of the Partnership (see Section 10.1 of the Agreement). The General Partner is authorized to engage legal counsel and otherwise to act with respect to Service audits, assessments and administrative and judicial proceedings as it deems in
the best interests of the Partnership and pursuant to the provisions of the Code. 
  
 The General Partner is granted a broad power of attorney authorizing it to execute certain documents required in connection with the organization, qualification, continuance, modification and termination of the
Partnership on behalf of the Limited Partners (see Sections 1.5 and 1.6 of the Agreement). Certain actions, such 

  

 65 

 
as an assignment for the benefit of its creditors or a sale of substantially all of the Partnership Properties, except in connection with the termination,
roll-up or consolidation of the Partnership, cannot be taken by the General Partner without the consent of a majority in interest of the Limited Partners and the receipt of an opinion of Conner & Winters as described under “Assignments by
the General Partner” below (see Sections 10.15 and 12.1 of the Agreement). 
  
 The Agreement provides that the General Partner will either conduct the Partnership’s drilling and production operations and operate each Partnership Well or arrange for a third party operator to conduct such
operations. The General Partner will, on behalf of the Partnership, enter into an appropriate operating agreement with the other owners of properties to be developed by the Partnership authorizing either the General Partner or a third party operator
to conduct such operations. The Partnership Agreement further provides that the Partnership will take such action in connection with operations pursuant to such operating agreements as the General Partner, in its sole discretion, deems appropriate
and in the best interests of the Partnership, and the decision of the General Partner with respect thereto will be binding upon the Partnership. 
  
 Rollup or Consolidation of the Partnership 
  
 Two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General
Partner may, without the vote, consent or approval of the Limited Partners, cause all or substantially all of the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or
consolidated with, another partnership or a corporation, trust or other entity for the purpose of combining the assets of two or more of the oil and gas partnerships formed for investment or participation by employees, directors and/or consultants
of UNIT or any of its subsidiaries; provided, however, that the valuation of the oil and gas properties and other assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a
manner which the General Partner and UNIT believe is fair and equitable to the Limited Partners. As a consequence of any such transfer or combination, the Partnership will be dissolved and terminated and the Limited Partners shall receive
partnership interests, stock or other equity interests in the transferee or resulting entity. See “RISK FACTORS — Investment Risks - Roll-Up or Consolidation of the Partnership.” 
  
 Limited Liability 
  
 Under the Act, a limited partner is not generally liable for partnership
obligations unless he or she takes part in the control of the business. The Agreement provides that the Limited Partners cannot bind or commit the Partnership or take part in the control of its business or management of its affairs, and that the
Limited Partners will not be personally liable for any debts or losses of the Partnership. However, the amounts contributed to the Partnership by the Limited Partners and the Limited Partners’ interests in Partnership assets, including amounts
of undistributed Partnership Revenue allocable to the Limited Partners, will be subject to the claims of creditors of the Partnership. A Limited Partner (or his or her estate) will be obligated to contribute cash to the Partnership, even if the
Limited Partner is unable to do so because of death, disability or any other reason, for: 
  
 (1) any unpaid contribution which the Limited Partner agreed to make to the Partnership; and 
  
 (2) any return, in whole or in part, of the Limited
Partner’s contribution to the extent necessary to discharge Partnership liabilities to all creditors who extended credit or whose claims arose before such return. 
  
 Liability of a Limited Partner is limited by the Act to one year for any return of his or her contribution not in violation
of the Partnership Agreement or such Act and six years on any return of his or her contribution in violation of the Partnership Agreement or such Act. A partner is deemed to have received a return of his or her contribution to the extent that a
distribution to him or her reduces his or her share of the fair value of the net assets of the Partnership below the value of his or her contribution which has not been distributed to him or her. How this provision applies to a partnership whose
primary assets are producing oil and gas properties or other depleting assets is not entirely clear. The Agreement provides that for the purposes of this provision, the value of a Limited Partner’s contribution which has not been distributed to
him or her at any point in time will be the Limited Partner’s Percentage of the stated capital of the Partnership allocated to the Limited Partners as reflected in its financial statements as of such point in time. 
  

 66 

 Maintenance of limited liability of the Limited Partners in other jurisdictions in which the Partnership
may operate may require compliance with certain legal requirements of those jurisdictions. In such jurisdictions, the General Partner shall cause the Partnership to operate in such a manner as it, on the advice of responsible Conner & Winters,
deems appropriate to avoid unlimited liability for the Limited Partners (see Sections 1.5, 12.1 and 12.2 of the Agreement). After the termination of the Partnership, any distribution of Partnership Properties to the Limited Partners would result in
their having unlimited liability with respect to such properties. 
  
 Although the Partnership will, with certain limited exceptions, serve as a co-general partner of any drilling or income programs formed by UNIT or UPC in 2005 (see “PROPOSED ACTIVITIES”), the general liability of the Partnership
will not flow through to the Limited Partners. 
  
 Records, Reports and
Returns 
  
 The General Partner will maintain adequate
books, records, accounts and files for the Partnership and keep the Limited Partners informed by means of written interim reports rendered within 60 days after each quarter of the Partnership’s fiscal year. The reports will set forth the source
and disposition of Partnership Revenues during the quarter. 
  
 Engineering reports on the Partnership Properties will be prepared by the General Partner for each year for which the General Partner prepares such a report in connection with its own activities. Such report will include an estimate of the
total oil and gas proven reserves of the Partnership, the dollar value thereof and the value of the Limited Partners’ interest in such reserve value. The report shall also contain an estimate of the life of the Partnership Properties and the
present worth of the reserves. Each Limited Partner will receive a summary statement of such report which will reflect the value of the Limited Partners’ interest in such reserves. 
  
 The General Partner will timely file the Partnership’s income tax returns and by March 15 of each year or as soon
thereafter as practicable, furnish each person who was a Limited Partner during the prior year all available information necessary for inclusion in his or her federal income tax return. (See Section 8.1 of the Agreement). 
  
 Transferability of Interests 
  
 Restrictions. A Limited Partner may not transfer or assign
Units except for certain transfers: 
  

	 	•	 	to the General Partner; 

  

	 	•	 	to or for the benefit of himself or herself, his or her spouse, or other members of the transferor Limited Partner’s immediate family sharing the same residence;

  

	 	•	 	to any corporation or other entity whose beneficial owners are all Limited Partners or permitted assignees; 

  

	 	•	 	by the General Partner to any person who at the time of such transfer is an employee of the General Partner, UNIT or its subsidiaries; and 

  

	 	•	 	by reason of death or operation of law. 

  
 Further, no sale or exchange of any Units may be made if the sale of such interest would, in the opinion of counsel for the Partnership, result in a
termination of the Partnership for purposes of Section 708 of the Code, violate any applicable securities laws or cause the Partnership to be treated as an association taxable as a corporation for federal income tax purposes; provided, however, that
this condition may be waived by the General Partner, in its sole discretion. Moreover, in no event shall all or any portion of a Limited Partner’s Units be assigned to a minor or an incompetent, except by will, intestate succession, in trust,
or pursuant to the Uniform Gifts to Minors Act. 
  
 As the offer
and sale of the Units are not being registered under the Securities Act of 1933, as amended, they may be sold, transferred, assigned or otherwise disposed of by a Limited Partner only if, in the opinion of counsel for the Partnership, such transfer
or assignment would not violate, or cause the offering of the Units to be violative of, such act or applicable state securities laws, including investor suitability standards thereunder. Because of the structure and anticipated operation of the
Partnership, Rule 144 under the Securities Act of 1933 will not be available to Limited Partners in connection with any such sales. 
  

 67 

 Assignees. An assignee of a Limited Partner does not automatically become a Substituted
Limited Partner, but has the right to receive the same share of Partnership Revenue and distributions thereof to which the assignor Limited Partner would have been entitled. A Limited Partner who assigns his or her Partnership interest ceases to be
a Limited Partner, except that until a Substituted Limited Partner is admitted in his or her place, the assignor retains the statutory rights of an assignor of a Limited Partner’s interest under the partnership laws of the State of Oklahoma.
The assignee of a Partnership interest who does not become a Substituted Limited Partner and desires to make a further assignment of such interest is subject to all of the restrictions on transferability of Partnership interests described herein and
in the Partnership Agreement. 
  
 In the event of the death,
incapacity or bankruptcy of a Limited Partner, his or her legal representatives will have all the rights of a Limited Partner only for the purpose of settling or liquidating his or her estate and such power as the decedent, incompetent or bankrupt
Limited Partner possessed to assign all or any part of his or her interest in the Partnership and to join with such assignee in satisfying conditions precedent to such assignee’s becoming a Substituted Limited Partner. 
  
 A purported sale, assignment or transfer of a Limited Partner’s interest
will be recognized by the Partnership when it has received written notice of such sale or assignment in form satisfactory to the General Partner, signed by both parties, containing the purchaser’s or assignee’s acceptance of the terms of
the Agreement and a representation by the parties that the sale or assignment was lawful. Such sale or assignment will be recognized as of the date of such notice, except that if such date is more than 30 days prior to the time of filing, such sale
or assignment will be recognized as of the time the notice was filed with the Partnership. Distributions of Partnership Revenue will be made only to those persons who were record owners of Units on the day any such distribution is made. 

 
 Substituted Limited Partners. No Limited Partner has the
right to substitute an assignee as a Limited Partner in his or her place. The General Partner, however, has the right in its sole discretion to permit such assignee to become a Substituted Limited Partner and any such permission by the General
Partner is binding and conclusive without the consent or approval of any Limited Partner. Any Substituted Limited Partner must, as a condition to receiving any interest of the Limited Partner, agree in writing to be bound by the terms and conditions
of the Partnership Agreement, pay or agree to pay the costs and expenses incurred by the Partnership in taking the actions necessary in connection with his or her substitution as a Limited Partner and satisfy the other conditions specified in
Article XIII of the Partnership Agreement. 
  
 Assignments
by the General Partner. The General Partner may not sell, assign, transfer or otherwise dispose of its interest in the Partnership except with the prior consent of a majority in interest of the Limited Partners, provided that no such consent
is required if the sale, assignment or transfer is pursuant to a bona fide merger, other corporate reorganization or complete liquidation, sale of substantially all of the General Partner’s assets (provided the purchasers agree to assume the
duties and obligations of the General Partner) or any sale or transfer to UNIT or any affiliate of UNIT. Any consent of the Limited Partners will not be effective without an opinion of counsel to the Partnership or an order or judgment of a court of
competent jurisdiction to the effect that the exercise of such right will not be deemed to evidence that the Limited Partners are taking part in the management of the Partnership’s business and affairs and will not result in a loss of any
Limited Partner’s limited liability or cause the Partnership to be classified as an association taxable as a corporation for federal income tax purposes (see Section 12.1 of the Agreement). Any transferee of the General Partner’s interest
may become a substitute General Partner by assuming and agreeing to perform all of the duties and obligations of a General Partner under the Agreement. In such event, the transferring General Partner, upon making a proper accounting to the
substitute General Partner, will be relieved of any further duties or obligations with respect to any future Partnership operations. 
  
 Amendments 
  
 The Agreement may be amended upon the approval by a majority in interest of the Limited Partners, except that amendments changing the Partners’
participation in costs and revenues, increasing or decreasing the General Partner’s compensation or otherwise materially and adversely affecting the interests of either the Limited 

  

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Partners or the General Partner must be approved by all Limited Partners if their interests would be adversely affected thereby or by the General Partner if
its interest would be adversely affected thereby. The Limited Partners have no right to propose amendments to the Agreement. 
  
 Voting Rights 
  
 Under the Agreement, the Limited Partners will have very limited rights to vote on any Partnership matters. Except for certain special amendments referred
to under “Amendments” above, matters submitted to the Limited Partners for determination will be determined by the affirmative vote of Limited Partners holding a majority of the outstanding Units. Units held by the General Partner may be
voted by it. 
  
 Generally, Limited Partners owning more than 50%
of the outstanding Units of the Partnership may, without the necessity of concurrence by the General Partner, vote to: 
  

	 	•	 	Approve the execution or delivery of any assignment for the benefit of the Partnership’s creditors; 

  

	 	•	 	Approve the sale or disposal of all or substantially all of the Partnership’s assets, except pursuant to (i) a rollup or consolidation of the Partnership (see “Rollup or
Consolidation of the Partnership” above) or (ii) termination (see “Termination” below); 

  

	 	•	 	Approve the General Partner’s sale, assignment, transfer or disposal of its interest in the Partnership, unless such sale, assignment or transfer is pursuant to (i) a merger or
other corporate reorganization, or liquidation or sale of substantially all of its assets, and the purchaser agrees to assume the duties and obligations of the General Partner, or (ii) any sale to UNIT or its affiliates; 

  

	 	•	 	Terminate and dissolve the Partnership; or 

  

	 	•	 	Approve any amendments to the Agreement which may be proposed by the General Partner; 

  
 provided, however, any approvals, consents or elections of the Limited Partners will not become effective unless prior to the exercise
thereof the General Partner is furnished with an opinion of counsel for the Partnership, or an order or judgment of any court of competent jurisdiction, that the exercise of such rights: 
  

	 	•	 	Will not be deemed to evidence that the Limited Partners are taking part in the control or management of the Partnership’s business affairs; 

  

	 	•	 	Will not result in the loss of any Limited Partner’s limited liability under the Act; and 

  

	 	•	 	Will not result in the Partnership being classified as an association taxable as a corporation for federal income tax purposes. 

  
 Exculpation and Indemnification of the General Partner 
  
 Pursuant to the Agreement, neither the General Partner or any affiliate
thereof will have any liability to the Partnership or to any Partners therein for any loss suffered by the Partnership or such Partner that arises out of any action or inaction of the General Partner or any affiliate thereof if the General Partner
or affiliate thereof in good faith determined that such course of conduct was in the best interest of the Partnership, the General Partner or affiliate was acting on behalf of or performing services for the Partnership, such liability or loss was
not the result of gross negligence or willful misconduct by the General Partner or affiliates thereof, and payments arising from such indemnification or agreement to hold harmless are receivable only out of the tangible net assets of the
Partnership. 
  
 Termination 
  
 The Partnership will terminate automatically on December 31, 2035. In
addition, upon the dissolution (other than pursuant to a merger, or other corporate reorganization or sale), bankruptcy, legal disability or withdrawal of the General Partner, the Partnership shall immediately be dissolved and terminated. The Act
provides, however, that the Limited Partners may elect to reform and reconstitute themselves as a limited partnership within 90 days after such dissolution under the provisions in the Partnership Agreement or under any 

  

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other terms. The Partnership may terminate sooner if a majority in interest of the Limited Partners or the General Partner elects to dissolve and terminate
the Partnership as of an earlier date. Such right to accelerate termination of the Partnership by the Limited Partners will not be available unless prior to any exercise thereof the Limited Partners proposing such termination obtain and furnish to
the General Partner an opinion, order or judgment in the form referred to above under “Transferability of Interests - Assignments by the General Partner.” The withdrawal, expulsion, dissolution, death, legal disability, bankruptcy or
insolvency of any Limited Partner will not effect a dissolution or termination of the Partnership. In the event of an election to terminate the Partnership prior to expiration of its stated terms, 90 days’ prior written notice must be given to
all Partners specifying the termination date which must be the last day of a calendar month following such 90 day period unless an earlier date is approved by Limited Partners holding a majority of the outstanding Units. 
  
 When the Partnership is terminated, there will be an accounting with respect
to its assets, liabilities and accounts. The Partnership’s physical property and its oil and gas properties may be sold for cash. Except in the case of an election by the General Partner to terminate the Partnership before the tenth anniversary
of the Effective Date, Partnership Properties may be sold to the General Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner. 
  
 Upon termination, all of the Partnership’s debts, liabilities and obligations, including expenses incurred in
connection with the termination and the sale or distribution of Partnership assets, will be paid. All Partnership borrowings will be paid in full. When the specified payments have all been made, the remaining cash and properties of the Partnership,
if any, will be distributed to the Partners as set forth under “Partnership Distributions” above (see Section 16.4 of the Agreement). Such distribution will result in the Limited Partners’ having unlimited liability with respect to
any Partnership Properties distributed to them. 
  
 Insurance

  
 The General Partner will use its best efforts to
obtain such insurance as it deems prudent to serve as protection against liability for loss and damage. Such insurance may include, but is not limited to, public liability, automotive liability, workers’ compensation and employer’s
liability insurance and blowout and control of well insurance. 
  
 COUNSEL 
  
 Conner & Winters, P.C., 3700 First
Place Tower, Tulsa, Oklahoma, has acted as special counsel to the General Partner in connection with certain aspects of this offering. Conner & Winters has assisted in the preparation of the Agreement and this Memorandum. In connection with the
preparation of this Memorandum, Conner & Winters has relied entirely upon information submitted to it by the General Partner. Certain of this information has been verified by Conner & Winters in the course of its representation, but no
systematic effort has been made to verify all of the material information contained herein, and much of such information is not subject to independent verification. In addition, Conner & Winters has made no independent investigation of the
financial information concerning the General Partner. Further, while passing on certain legal matters, Conner & Winters has not passed on the investment merits nor is it qualified to do so. Because substantial portions of the information
contained in this Memorandum have not been independently verified, each investor must make whatever independent inquiries the investor or his or her advisors deem necessary or desirable to verify or confirm the statements made herein. 
  
 GLOSSARY 
  
 As used herein and in the Agreement, the following terms and phrases will have the meanings indicated. 
  
 (a) “Additional Assessments” are amounts required to
be contributed by the Limited Partners to the Partnership upon a call therefore by the General Partner in the manner described under “ADDITIONAL FINANCING — Additional Assessments.” 
  
 (b) An “affiliate” of another person is (1) any
person directly or indirectly owning, controlling or holding with power to vote 10% or more of the outstanding voting securities of such other person; (2) any person 

  

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10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by such other person; (3) any
person directly or indirectly controlling, controlled by, or under common control with such other person; (4) any officer, director, trustee or partner of such other person; and (5) if such other person is an officer, director, trustee or partner,
any company for which such person acts in any such capacity. 
  
 (c) The “Aggregate Subscription” is the sum of the Capital Subscriptions of all Limited Partners. 
  
 (d) “Agreement” and “Partnership Agreement” refers to the Agreement of Limited Partnership attached as
Exhibit A to this Private Offering Memorandum. 
  
 (e) The
“Capital Contribution” of a Limited Partner is the amount of the Capital Subscription actually paid in by him or her, or by any predecessor in interest, to the capital of the Partnership including any payments made by
deductions from salary. The “Capital Contribution” of the General Partner includes the amounts contributed to the Partnership or paid by the General Partner or by any Limited Partner whose Units are purchased by the General Partner
pursuant to Section 4.2 of the Agreement because of a default by such Limited Partner in the payment of an Installment or pursuant to Article XV of the Agreement, including payments made by deductions from the salary of such Limited Partner.

  
 (f) The “Capital Subscription” of a
Limited Partner or his or her assignee (including the General Partner where Units are transferred pursuant to Section 4.2 of the Agreement) is the amount specified in the Subscription Agreement executed by such Limited Partner for payment by him or
her to the capital of the Partnership in accordance with the provisions of the Agreement, reduced by the amounts thereof from which the Limited Partners have been released by the General Partner of their obligation to pay. 
  
 (g) A “Development Well” means a well intended to be
drilled within the proved areas of a known oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. 
  
 (h) “Director” refers to the duly elected directors of UNIT as well as all honorary directors and consultants to the Board of
Directors of UNIT. 
  
 (i) “Drilling
Costs” are those costs incurred in drilling, testing, completing and equipping a well to the point that it proves to be dry and is abandoned or is ready to commence commercial production of oil or gas therefrom. 
  
 (j) “Effective Date” refers to the date on which the
certificate evidencing formation of the Partnership is filed with the Secretary of State of the State of Oklahoma as required by the Act (54 Okla. Stat. 2001, Section 309). 
  
 (k) An “Exploratory Well” means a well drilled to find production in an unproven area, to find a new
reservoir in a field previously found to be productive or to extend greatly the limits of a known reservoir. 
  
 (l) A “farm-out” is an agreement whereby the owner of an oil and gas property agrees to assign such property, usually retaining
some interest therein such as an overriding royalty, a production payment, a net profits interest or a carried working interest, subject in most cases, however, to the drilling of one or more wells or other performance by the prospective assignee as
a condition of the assignment. 
  
 (m) The “General
Partner’s Minimum Capital Contribution” is that amount equal to the total of (i) all Partnership costs and expenses charged to its account from the time of the formation of the Partnership through December 31, 2005, plus (ii) the
General Partner’s estimate of the total Leasehold Acquisition Costs and Drilling Costs expected to be incurred by the Partnership subsequent to December 31, 2005, if any, minus (iii) the amount, if any, of the unexpended Aggregate Subscription
at December 31, 2005. 
  
 (n) The “General
Partner’s Percentage” is that percentage determined by dividing the amount of the General Partner’s Minimum Capital Contribution by the total of (i) the General Partner’s Minimum Capital Contribution plus (ii) the
Aggregate Subscription. 
  
 (o)
“Installments” refer to the periodic payments of the Capital Subscription, which are payable either (i) in four equal installments due on March 15, June 15, September 15, 2005 and December 15, 2005, respectively, or (ii) if
an employee so elects, through equal deductions from 2005 salary commencing immediately after formation of the Partnership. 
  

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 (p) “Leasehold Acquisition Costs” with respect to properties, if any, acquired by
the Partnership from non-affiliated parties mean the actual costs to the Partnership of and in acquiring the properties, and, with respect to properties acquired by the Partnership from the General Partner, UNIT or its affiliates are, without
duplication, the sum of: 
  

	 	(1)	the prices paid by the General Partner, UNIT or its affiliates in acquiring an oil and gas property, including purchase option fees and charges, bonuses and penalties, if any;

  

	 	(2)	title insurance or examination costs, broker’s commissions, filing fees, recording costs, transfer taxes, if any, and like charges incurred in connection with the acquisition
of such property; 

  

	 	(3)	a pro rata portion of the actual, necessary and reasonable expenses of the General Partner, UNIT or its affiliates for seismic and geophysical services; 

  

	 	(4)	rentals, shut-in royalties and ad valorem taxes paid by the General Partner, UNIT or its affiliates with respect to such property to the date of its transfer to the Partnership;

  

	 	(5)	interest and points actually incurred on funds used by the General Partner, UNIT or its affiliates to acquire or maintain such property; and 

  

	 	(6)	such portion of the General Partner’s, UNIT or its affiliates’ reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other
like services allocated to the acquisition, operations and maintenance of the property in accordance with generally accepted industry practices, except for expenses in connection with the past drilling of wells which are not producers of sufficient
quantities of oil or gas to make commercially reasonable their continued operations, and provided that the costs and expenses enumerated in (4), (5) and (6) above with respect to any particular property shall have been incurred not more than
thirty-six (36) months prior to the acquisition of such property by the Partnership. 

  
 In the event a fractional undivided interest in a property is sold or transferred by the General Partner, UNIT or any affiliate to an unaffiliated third party for an amount in excess of that portion of the original
cost of the property attributable to the transferred interest, the amount of such excess shall not reduce or be offset against the amount of the Leasehold Acquisition Costs attributable to any interest in the same property which is transferred to
the Partnership. 
  
 (q) “Limited
Partners” are those persons who acquire Units in the Partnership upon its formation and those transferees of Units who are accepted as Substituted Limited Partners. The General Partner may also be a Limited Partner if it subscribes for
Units or if it subsequently acquires Units by (i) the exercise by a Limited Partner of his or her right of presentment; (ii) a purchase by the General Partner of the Units of a Limited Partner who defaults in the payment of an Installment; or (iii)
any other assignment or transfer. 
  
 (r) The “Limited
Partners’ Percentage” is that percentage determined by dividing the amount of the Aggregate Subscription by the total of (i) the General Partner’s Minimum Capital Contribution plus (ii) the Aggregate Subscription. 

 
 (s) “Normal Retirement” means retirement under the
terms of a pension or similar retirement plan adopted by the General Partner, UNIT or any subsidiary with whom a Limited Partner is employed as in effect at the time of retirement. 
  
 (t) “Oil and gas properties” are oil and gas leasehold working interests, fee interests, mineral
interests, royalty interests, overriding royalty interests, production payments, options or rights to lease or acquire such interests, geophysical exploration permits and any tangible or intangible properties or other rights incident thereto,
whether real, personal or mixed. 
  
 (u) “Operating
Expenses” are expenditures made and costs incurred in producing and marketing oil or gas from completed wells, including, in addition to labor, fuel, repairs, hauling, material, supplies, utility 

  

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charges and other costs incident to or necessary for the maintenance or operation of such wells or the marketing of production therefrom, ad valorem,
severance and other such taxes (other than windfall profit taxes), insurance and casualty loss expense and compensation to well operators or others for services rendered in conducting such operations. 
  
 (v) The General Partner and the Limited Partners are sometimes collectively
referred to as the “Partners.” 
  
 (w)
“Partnership Agreement” and “Agreement” refer to the Agreement of Limited Partnership attached as Exhibit A to this Private Offering Memorandum. 
  
 (x) The “Partnership Properties” are oil and gas
properties or interests therein acquired by the Partnership or properties acquired by any partnership or joint venture in which the Partnership is a partner or joint venturer, whether acquired by purchase, option exercise or otherwise. 

 
 (y) “Partnership Revenue” refers to the
Partnership’s gross revenues from all sources, including interest income, proceeds from sales of production, the Partnership’s share of revenues from partnerships or joint ventures of which it is a member, sales or other dispositions of
Partnership Properties or other Partnership assets, provided that contributions to Partnership capital by the Partners and the proceeds of any Partnership borrowings are specifically excluded and dry-hole and bottom-hole contributions shall be
treated as reductions of the costs giving rise to the right to receive such contributions. 
  
 (z) “Partnership Wells” are any and all of the oil and gas wells in which the Partnership has an interest, either directly or indirectly through any other partnership or joint venture.

  
 (aa) “Productive properties” are oil
and gas properties that have been tested by drilling and determined to be capable of producing oil or gas in commercial quantities. 
  
 (bb) A “spacing unit” is a drilling and spacing, production or similar unit established by any regulatory body with jurisdiction,
or in the absence of such a regulatory body or action thereby, the acreage attributable to wells drilled under the normal spacing pattern in such area or if no such spacing unit is designated, in keeping with generally accepted industry practices,
or the largest of such units in the event of multiple objective formations. 
  
 (cc) “Special Production and Marketing Costs” are costs and expenses that are not normally and customarily incurred in connection with drilling, producing and marketing operations, including
without limitation, costs incurred in constructing compressor plants, gasoline plants, gas gathering systems, natural gas processing plants, pipeline systems and salt water disposal systems and costs incurred in installing pressure maintenance and
secondary or tertiary production projects. 
  
 (dd)
“Subscription Agreement” refers to the form of Limited Partner Subscription Agreement and Suitability Statement attached as Attachment I to the Partnership Agreement. 
  
 (ee) A “Substituted Limited Partner” is a transferee,
donee, heir, legatee or other recipient of all or any portion of a Limited Partner’s interest in the Partnership with respect to whom all conditions and consents required to become a Substituted Limited Partner under Article XIII of the
Partnership Agreement have been satisfied and given. 
  
 (ff) A
“Unit” is a preformation unit of limited partnership interest of a Limited Partner in the Partnership representing a Capital Subscription of One Thousand Dollars ($1,000). 
  
 FINANCIAL STATEMENTS 
  
 On January 1, 1988 all of the oil and natural gas properties previously owned
by Unit Drilling and Exploration Company (“UDEC”) and UNIT were transferred into Sunshine Development Company through a contribution of capital. Included in the transfer were all interests previously owned by UDEC in numerous
General and Limited Partnerships sponsored by UDEC. Effective February 1, 1988, Sunshine Development Company, a wholly owned subsidiary of UDEC, pursuant to an “Amended and Restated Certificate of Incorporation” was renamed Unit Petroleum
Company and became a wholly owned subsidiary of UNIT. 
  

 73 

 Unit Petroleum Company functions as the operating entity for all oil and natural gas exploration and
production activities including operating any partnerships for UNIT. 
  
 The consolidated balance sheet of Unit Petroleum Company at October 31, 2004 is unaudited and includes all adjustments which UNIT considers necessary for a fair presentation of the financial position of Unit Petroleum Company at October 31,
2004. 
  
 Unit Petroleum Company 
 Consolidated Balance Sheet 
 (In Thousands)

  

				
	 	  	October 31, 2004
(Unaudited)

	 Assets
	  	 	 
	 Current Assets:
	  	 	 
	 Cash and cash equivalents
	  	$	563
	 Trade accounts receivable
	  	 	22,175
	 Materials and supplies, at lower of cost or market
	  	 	7,339
	 Other
	  	 	370
	 	  	
	

	 Total current assets
	  	 	30,447
	 	  	
	

	 Property and Equipment:
	  	 	 
	 Oil and natural gas properties, on the full cost method
	  	 	622,260
	 Other
	  	 	424
	 	  	
	

	 	  	 	622,684
		
	 Less accumulated depreciation, depletion, amortization and impairment
	  	 	272,410
	 	  	
	

	 Net property and equipment
	  	 	350,274
	 	  	
	

	 Other Assets
	  	 	43
	 	  	
	

	 Total Assets
	  	$	380,764
	 	  	
	

	 Liabilities and Shareholders’ Equity
	  	 	 
	 Current Liabilities:
	  	 	 
	 	  	 	 
	 Current portion of long-term liabilities
	  	 	226
	 Accounts payable
	  	 	10,199
	 Accounts payable to parent
	  	 	10,782
	 Contract advances
	  	 	1,208
	 Accrued liabilities
	  	 	1,735
	 	  	
	

	 Total current liabilities
	  	 	24,150
	 	  	
	

	 Other Long-Term Liabilities
	  	 	14,082
	 	  	
	

	 Deferred Income Taxes
	  	 	94,419
	 	  	
	

	 Shareholders’ Equity:
	  	 	 
	 Common stock, $1.00 par value, 500 shares authorized and outstanding
	  	 	1
	 Capital in excess of par value
	  	 	31,543
	 Retained earnings
	  	 	216,569
	 	  	
	

	 Total shareholders’ Equity
	  	 	248,113
	 	  	
	

	 Total Liabilities and Shareholders’ Equity
	  	$	380,764
	 	  	
	

  

 74 

 EXHIBIT A 
  

UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP 
  
 AGREEMENT OF LIMITED PARTNERSHIP 
  

 A-1 

 INDEX 
  

					
	 ARTICLE I Formation of Limited Partnership
	  	3
		
	 ARTICLE II Definitions
	  	4
		
	 ARTICLE III Purposes and Powers of the Partnership
	  	7
		
	 ARTICLE IV Partner Capital Contributions
	  	8
		
	 ARTICLE V Deposit and Use of Capital Contributions and Other Partnership Funds
	  	10
		
	 ARTICLE VI Sharing of Costs, Capital Accounts and Allocation of Charges and Income
	  	11
		
	 ARTICLE VII Fiscal Year, Accountings and Reports
	  	15
		
	 ARTICLE VIII Tax Returns and Elections
	  	15
		
	 ARTICLE IX Distributions
	  	16
		
	 ARTICLE X Rights, Duties and Obligations of the General Partner
	  	16
		
	 ARTICLE XI Compensation and Reimbursements
	  	20
		
	 ARTICLE XII Rights and Obligations of Limited Partners
	  	21
		
	 ARTICLE XIII Transferability of Limited Partner’s Interest
	  	21
		
	 ARTICLE XIV Assignments by the General Partner
	  	23
		
	 ARTICLE XV Limited Partners’ Right of Presentment
	  	24
		
	 ARTICLE XVI Termination and Dissolution of Partnership
	  	25
		
	 ARTICLE XVII Notices
	  	27
		
	 ARTICLE XVIII Amendments
	  	27
		
	 ARTICLE XIX General Provisions
	  	27
			
	 ATTACHMENT I
	  	Limited Partner Subscription Agreement and Suitability Statement	  	I-1

  
  

 A-2 

 UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP 
 AGREEMENT OF LIMITED PARTNERSHIP 
  
 THIS AGREEMENT OF LIMITED PARTNERSHIP (this “Agreement”) is made and entered into by and among Unit Petroleum Company, an Oklahoma
corporation, hereinafter referred to as the “General Partner” or “UPC” (which term shall include any successors or assigns of UPC), and each of those persons who have executed a counterpart of the Limited Partner
Subscription Agreement and Suitability Statement attached as Attachment I to this Agreement that have been accepted by the General Partner, said persons being hereinafter collectively referred to as the “Limited Partners.”

  
 WITNESSETH THAT: 
  
 ARTICLE I 
 Formation of Limited Partnership 
  
 1.1 The parties to this Agreement hereby form a Limited Partnership (the “Partnership”) pursuant to the Revised Uniform Limited Partnership Act of the State of Oklahoma (the “Act”).
The terms and provisions hereof will be construed and interpreted in accordance with the terms and provisions of the Act and if any of the terms and provisions of this Agreement should be deemed inconsistent with those terms and provisions of the
Act which under the Act may not be altered by agreement of the parties, the Act will be controlling, but otherwise this Agreement will be controlling. 
  
 1.2 The Partnership will be conducted under the name of “Unit 2005 Employee Oil and Gas Limited Partnership” in Oklahoma, and under such name or
variations of such name as the General Partner deems appropriate to comply with the laws of the other jurisdictions in which the Partnership does business. 
  
 1.3 The principal office of the Partnership will be 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136, or at such other location as may from time to
time be designated by the General Partner, and the Partnership’s agent for service of process shall be Unit Corporation (“UNIT,” which term shall include all or any of its subsidiaries or affiliates unless the context otherwise
requires) at the same address. 
  
 1.4 The Partnership will be
effective on the date on which the certificate evidencing formation of the Partnership is filed with the Secretary of State of the State of Oklahoma. Its business and operations will not be commenced prior to such date. The Partnership will continue
in existence until December 31, 2035, unless sooner terminated pursuant to any provisions of this Agreement. 
  
 1.5 The parties hereto will execute such certificates and other documents, and the General Partner will file, record and publish such certificates and
documents, as may be necessary or appropriate to comply with the requirements for the formation and operation of a limited partnership under the Act and as the General Partner, upon advice of counsel, deems necessary or appropriate to comply with
requirements of applicable laws governing the formation and operations of a limited partnership (or a partnership in which special partners have a limited liability) in all other jurisdictions where the Partnership desires to conduct business,
including, but not limited to, filings under the Fictitious Name Act, Assumed Name Act or similar law in effect in the counties, parishes and other governmental jurisdictions in which the Partnership conducts business. The General Partner shall not
be required to deliver or mail a copy of the certificate of limited partnership or any amendments thereto filed pursuant to the Act to the Limited Partners. 
  
 1.6 Each Limited Partner by his or her execution of a counterpart of the Subscription Agreement irrevocably constitutes and appoints the General Partner
such Limited Partner’s true and lawful attorney and agent, with full power and authority in such Limited Partner’s name, place and stead, to execute, sign, acknowledge, swear to, deliver, file and record in the appropriate public offices
(i) all certificates or other instruments (including, without limitation, counterparts of this Agreement) and 

  

 A-3 

 
amendments thereto which the General Partner deems appropriate to qualify or continue the Partnership as a limited partnership (or a partnership in which
special partners have limited liability) in the jurisdictions in which the Partnership conducts business; (ii) all instruments and amendments thereto which the General Partner deems appropriate to reflect any change or modification of this
Agreement, the admission of additional or substitute Partners in accordance with the terms of this Agreement, the release or waiver of the Limited Partners from the obligation to pay in one or more of the installments of their Capital Subscriptions
pursuant to Section 4.2 below and the termination of the Partnership and the cancellation of the certificate of limited partnership; (iii) all conveyances and other instruments which the General Partner deems appropriate to evidence and reflect any
sales or transfers, including sales or transfers upon or in connection with the dissolution and termination of the Partnership; and (iv) all consents to transfers of Partnership interests, to the admission of substitute or additional Partners or to
the withdrawal or reduction of any Partner’s invested capital, to the extent that such actions are authorized by the terms of this Agreement. The Power of Attorney granted herein is irrevocable and is a power coupled with an interest and will
survive the death, disability, dissolution, bankruptcy, insolvency or incapacity of a Limited Partner. 
  
 ARTICLE II 
 Definitions 
  
 2.1 Whenever used in this Agreement the following terms will have the
meanings described below: 
  
 (a) The
“Additional Assessments” of the Limited Partners are those amounts, if any, which they are required to pay into the capital of the Partnership pursuant to Section 5.3 of this Agreement. 
  
 (b) An “affiliate” of another person
is (1) any person directly or indirectly owning, controlling or holding with power to vote 10% or more of the outstanding voting securities of such other person; (2) any person 10% or more of whose outstanding voting securities are directly or
indirectly owned, controlled, or held with power to vote, by such other person; (3) any person directly or indirectly controlling, controlled by, or under common control with such other person; (4) any officer, director, trustee or partner of such
other person; and (5) if such other person is an officer, director, trustee or partner, any company for which such person acts in any such capacity. 
  
 (c) The “Aggregate Subscription” is the sum of the Capital Subscriptions of all Limited Partners. 
  
 (d) The “Capital Contribution” of a
Limited Partner is the amount of the Capital Subscription actually paid in by him or her, or by any predecessor in interest, to the capital of the Partnership, including any payments made by deductions from salary. The “Capital
Contribution” of the General Partner includes the amounts contributed to the Partnership or paid by the General Partner or by any Limited Partner whose Units are purchased by the General Partner including purchases pursuant to Section 4.2 of
this Agreement because of a default by such Limited Partner in the payment of a subscription installment or pursuant to Article XV of this Agreement, including payments made by deductions from the salary of such Limited Partner. 
  
 (e) The “Capital Subscription” of a
Limited Partner or his or her assignee (including the General Partner where Units are transferred pursuant to Section 4.2 of this Agreement) is the amount specified in the Subscription Agreement executed by such Limited Partner for payment by him or
her to the capital of the Partnership in accordance with the provisions of this Agreement, reduced by the amount thereof from which the Limited Partner has been released by the General Partner of his or her obligation to pay pursuant to Section 4.2
hereof. 
  

 A-4 

 (f) “Drilling Costs” are those costs incurred in drilling,
testing, completing and equipping a Partnership Well to the point that it proves to be dry and is abandoned or is ready to commence commercial production of oil or gas therefrom. 
  
 (g) “Effective Date” refers to the date on which the certificate evidencing
formation of the Partnership is filed with the Secretary of State of the State of Oklahoma as required by the Act (54 Okla. Stat. 2001, Section 309). 
  
 (h) A “farm-out” is an agreement whereby the owner of an oil and gas property agrees to assign such property,
usually retaining some interest therein such as an overriding royalty, a production payment, a net profits interest or a carried working interest, subject in most cases, however, to the drilling of one or more wells or other performance by the
prospective assignee as a condition of the assignment. 
  
 (i) The “General Partner’s Minimum Capital Contribution” is that amount equal to the total of (i) all Partnership costs and expenses charged to its account from the time of the formation of the Partnership
through December 31, 2005, plus (ii) the General Partner’s estimate of the total Leasehold Acquisition Costs and Drilling Costs expected to be incurred by the Partnership subsequent to December 31, 2005, minus (iii) the amount, if any, of the
unexpended Aggregate Subscription at December 31, 2005. 
  
 (j) The “General Partner’s Percentage” is that percentage determined by dividing the amount of the General Partner’s Minimum Capital Contribution by the total of (i) the General
Partner’s Minimum Capital Contribution plus (ii) the Aggregate Subscription. 
  
 (k) “Leasehold Acquisition Costs” with respect to properties, if any, acquired by the Partnership from
non-affiliated parties mean the actual costs to the Partnership of and in acquiring the properties, and, with respect to properties acquired by the Partnership from the General Partner, UNIT or its affiliates, are, without duplication, the sum of:
(1) the prices paid by the General Partner, UNIT or its affiliates in acquiring an oil and gas property, including purchase option fees and charges, bonuses and penalties, if any; (2) title insurance or examination costs, broker’s commissions,
filing fees, recording costs, transfer taxes, if any, and like charges incurred in connection with the acquisition of such property; (3) a pro rata portion of the actual, necessary and reasonable expenses of the General Partner, UNIT or its
affiliates for seismic and geophysical services; (4) rentals, shut-in royalties and ad valorem taxes paid by the General Partner, UNIT or its affiliates with respect to such property to the date of its transfer to the Partnership; (5) interest and
points actually incurred on funds used by the General Partner, UNIT or its affiliates to acquire or maintain such property; and (6) such portion of the General Partner’s, UNIT’s or its affiliates’ reasonable, necessary and actual
expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the acquisition, operations and maintenance of the property in accordance with generally accepted industry practices, except for expenses in
connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the costs and expenses enumerated in (4), (5) and (6) above with
respect to any particular property shall have been incurred not more than thirty-six (36) months prior to the acquisition of such property by the Partnership. In the event a fractional undivided interest in a property is sold or transferred by the
General Partner, UNIT or any affiliate to an unaffiliated third party for an amount in excess of that portion of the original cost of the property attributable to the transferred interest, the amount of such excess shall not reduce or be offset
against the amount of the Leasehold Acquisition Costs attributable to any interest in the same property which is transferred to the Partnership. 
  
 (l) “Limited Partners” are those persons who acquire Units in the Partnership upon its formation and those
transferees of Units who are accepted as Substituted Limited Partners. The General Partner may also be a Limited Partner if it subscribes for Units or if it subsequently acquires Units by (i) the exercise by a Limited Partner of his or her right of
presentment; (ii) a purchase by the General Partner of the Units of a Limited Partner who defaults in the payment of any subscription installment; or (iii) any other assignment or transfer. 
  

 A-5 

 (m) The “Limited Partners’ Percentage” is that percentage
determined by dividing the amount of the Aggregate Subscription by the total of (i) the General Partner’s Minimum Capital Contribution plus (ii) the Aggregate Subscription. 
  
 (n) “Normal Retirement” means retirement under the provision of a pension or similar
retirement plan adopted by the General Partner, UNIT or any subsidiary with whom a Limited Partner is employed as in effect at the time of the employee’s retirement. 
  
 (o) “Oil and gas properties” are oil and gas leasehold working interests, fee
interests, mineral interests, royalty interests, overriding royalty interests, production payments, options or rights to lease or acquire such interests, geophysical exploration permits and any tangible or intangible properties or other rights
incident thereto, whether real, personal or mixed. 
  
 (p) “Operating Expenses” are expenditures made and costs incurred in producing and marketing oil or gas from completed wells, including, in addition to labor, fuel, repairs, hauling, material, supplies, utility
charges and other costs incident to or necessary for the maintenance or operation of such wells or the marketing of production therefrom, ad valorem, severance and other such taxes (other than windfall profit taxes), insurance and casualty loss
expense and compensation to well operators or others for services rendered in conducting such operations. 
  
 (q) The General Partner and the Limited Partners are sometimes collectively referred to as the “Partners.”

  
 (r) The “Partnership
Properties” are oil and gas properties or interests therein acquired by the Partnership or properties acquired by any partnership or joint venture in which the Partnership is a partner or joint venturer, whether acquired by purchase,
option exercise or otherwise. 
  
 (s)
“Partnership Revenue” refers to the Partnership’s gross revenues from all sources, including interest income, proceeds from sales of production, the Partnership’s share of revenues from partnerships or joint
ventures of which it is a member, sales or other dispositions of Partnership Properties or other Partnership assets, provided that contributions to Partnership capital by the Partners and the proceeds of any Partnership borrowings are specifically
excluded and dry-hole and bottom-hole contributions shall be treated as reductions of the costs giving rise to the right to receive such contributions. 
  
 (t) “Partnership Wells” are any and all of the oil and gas wells in which the Partnership has an interest, either
directly or indirectly through any other partnership or joint venture. 
  
 (u) “Productive properties” are oil and gas properties that have been tested by drilling and determined to be capable of producing oil or gas in commercial quantities. 
  
 (v) “Special Production and Marketing
Costs” are costs and expenses that are not normally and customarily incurred in connection with drilling, producing and marketing operations, including without limitation, costs incurred in constructing compressor plants, gasoline
plants, gas gathering systems, natural gas processing plants, pipeline systems and salt water disposal systems and costs incurred in installing pressure maintenance and secondary or tertiary production projects. 
  
 (w) “Subscription Agreement” refers
to the form of Limited Partner Subscription Agreement and Suitability Statement attached as Attachment I to this Agreement. 
  

 A-6 

 (x) A “Substituted Limited Partner” is a transferee, donee, heir,
legatee or other recipient of all or any portion of a Limited Partner’s interest in the Partnership with respect to whom all conditions and consents required to become a Substituted Limited Partner under Article XIII have been satisfied and
given. 
  
 (y) A “Unit”
is a preformation unit of limited partnership interest of a Limited Partner in the Partnership representing a Capital Subscription of One Thousand Dollars ($1,000). 
  
 ARTICLE III 
 Purposes and Powers of the Partnership 
  
 3.1 The
purposes of the Partnership will be to acquire productive oil and gas properties and to explore for, produce, treat, transport and market oil, gas or both, or products derived therefrom, anywhere in the United States. It is contemplated that all or
most of the Partnership’s operations will be conducted as part of the operations of the General Partner and its affiliates, but the Partnership may engage in operations on its own or in conjunction with unaffiliated third parties. In
accomplishing such purposes the Partnership may: 
  
 (a) acquire oil and gas properties, either alone or in conjunction with other parties; 
  
 (b) conduct geological and geophysical investigations, including, without limitation, seismic exploration, core drilling and other means
and methods of exploration; 
  
 (c) drill, equip,
complete, rework, reequip, recomplete, plug back, deepen, plug and abandon Partnership Wells as the General Partner deems advisable; 
  
 (d) acquire and dispose of tangible lease and well equipment for use or used in connection with Partnership Wells; 
  
 (e) employ or retain such personnel and obtain such legal,
accounting, geological, geophysical, engineering and other professional services and advice as the General Partner may deem advisable in the course of the Partnership’s operations under this Agreement; 
  
 (f) either pay or elect not to pay delay rentals or shut-in
royalties on Partnership Properties as appropriate in the judgment of the General Partner, it being understood that the General Partner will not be liable for failure to make correct or timely payments of delay rentals or shut-in royalties if such
failure was due to any reason other than gross negligence or lack of good faith; 
  
 (g) make or give dry-hole or bottom-hole or other contributions of oil and gas properties, money or both, to encourage drilling by others
in the vicinity of or on Partnership Properties; 
  
 (h) negotiate for and accept dry-hole, bottom-hole or other contributions of oil and gas properties, cash or both, as consideration for the drilling of a Partnership Well, with oil and gas properties so acquired, if any, to become
Partnership Properties; 
  
 (i) pay all ad
valorem taxes levied or assessed against the Partnership Properties, all taxes upon or measured by the production of oil or gas or other hydrocarbons therefrom, and all other taxes (other than income taxes) directly relating to operations conducted
under this Agreement; 
  
 (j) enter into and
operate pursuant to operating agreements with respect to Partnership Properties naming either the General Partner, any of its affiliates or a third party as operator, or enter into partnership agreements with third parties whereby the Partnership
may be either a general or a limited partner (including any partnerships formed or sponsored by the General Partner or in which the General Partner may also be a partner), which operating or partnership agreements shall contain such terms,
provisions and conditions as the General Partner deems appropriate; 
  

 A-7 

 (k) execute all documents or instruments of any kind which the General Partner deems
appropriate for carrying out the purposes of the Partnership, including, without limitation, unitization agreements, gasoline plant contracts, recycling agreements and agreements relating to pressure maintenance and secondary or tertiary production
projects; 
  
 (l) purchase and establish
inventories of equipment and material required or expected to be required in connection with its operations; 
  
 (m) contract or enter into agreements with unaffiliated third parties, the General Partner or its affiliates for the performance of
services and the purchase and sale of material, equipment, supplies and property, both real and personal, provided, however, that any such contracts or agreements with the General Partner or any of its affiliates shall, except as otherwise provided
herein, provide for prices, fees, rates, charges or other compensation which are not greater than those available from, being paid to or charged by unaffiliated third parties dealing at arm’s length in the same or a similar geographic area for
the same or comparable services, material, equipment, supplies or property; 
  
 (n) conduct operations either alone or as a joint venturer, co-tenant, partner or in any other manner of participation with third persons and to enter into agreements and contracts setting forth the terms and
provisions of such participation; 
  
 (o) borrow
money from banks and other lending institutions for Partnership purposes and pledge Partnership Properties (including production therefrom) for the repayment of such loans, it being understood that no bank or other lending institution to which the
General Partner makes application for a loan will be required to inquire as to the purposes for which such loan is sought, and as between the Partnership and such bank or lending institution it will be conclusively presumed that the proceeds of such
loan are to be and will be used for purposes authorized under the terms of this Agreement; 
  
 (p) hold Partnership Properties in its own name or in the name of the General Partner, UNIT or any affiliate or any other party as nominee
for the Partnership; 
  
 (q) sell, relinquish,
release, farm-out, abandon or otherwise dispose of Partnership Properties, including undeveloped, productive and condemned properties; 
  
 (r) produce, treat, transport and market oil and gas and execute division orders, contracts for the marketing or sale of oil, gas or other
hydrocarbons and other marketing agreements; 
  
 (s) purchase, sell or pledge payments out of production from Partnership Properties; and 
  
 (t) perform any and all other acts or activities customary or incident to exploration for or development, production and marketing of oil
and gas. 
  
 ARTICLE IV 
 Partner Capital Contributions 
  
 4.1 The General Partner will have the unrestricted right to admit such parties as Limited Partners as it deems advisable. By their execution of the
Subscription Agreement, the Limited Partners severally agree, subject to the acceptance of their subscription by the General Partner, to be bound by the terms hereof as Limited Partners. 
  

 A-8 

 4.2 The Capital Subscriptions of the Limited Partners will be payable either (i) in four equal
installments on March 15, 2005, June 15, 2005, September 15, 2005, and December 15, 2005, respectively, or (ii) by employees so electing, through equal deductions from 2005 salary paid to the employee by the General Partner, UNIT or its subsidiaries
commencing immediately after the Effective Date. Notwithstanding the foregoing, if in the judgment of the General Partner, the entire amount of the Aggregate Subscription is not required for purposes of conducting the business, operations and
affairs of the Partnership, the General Partner may, at its sole option, elect to release the Limited Partners from the obligation to pay in one or more of the installments of their Capital Subscriptions. If Units are acquired by a corporation or
other entity, the beneficial owners of the interests therein shall be jointly and severally liable for the payment of the Capital Subscription. If an employee or director who has subscribed for Units (either directly or through a corporation or
other entity) ceases to be employed by or a director of the General Partner, UNIT or any of its subsidiaries for any reason other than death, disability or Normal Retirement prior to the time the full amount of his or her Capital Subscription is
paid, then the due date for any unpaid amount shall be accelerated so that the full amount of his or her unpaid Capital Subscription shall be due and payable on the effective date of such termination. The Capital Subscriptions shall be legally
binding obligations of the Limited Partners and any past due amounts shall bear interest at the annual rate equal to two (2) percentage points in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as
announced and in effect from time to time, until paid. Further, in the event a Limited Partner fails to pay any installment when due, the General Partner, at its sole option and discretion, may elect to purchase the Units of such defaulting Limited
Partner at a price equal to the total amount of the Capital Contributions actually paid into the Partnership by such defaulting Limited Partner, less the amount of any Partnership distributions that may have been received by him or her. Such option
may be exercised by the General Partner by written notice to the Limited Partner at any time after the date that the unpaid installment was due and shall be deemed exercised when the amount of the purchase price is first tendered to the defaulting
Limited Partner. The General Partner may, in its discretion, accept payments of delinquent installments but shall not be required to do so. In the event that the General Partner elects to purchase the Units of a defaulting Limited Partner, it shall
pay into the Partnership the amount of the delinquent installment (excluding any interest that may have accrued thereon) and shall pay each additional installment, if any, payable with respect to such Units as it becomes due. By virtue of such
purchase, the General Partner shall be allocated all Partnership Revenues and be charged with all Partnership costs and expenses attributable to such Units otherwise allocable or chargeable to the defaulting Limited Partner to the extent provided in
Section 13.9. 
  
 4.3 If the Partnership requires funds to conduct
Partnership operations during the period between any of the installments due as set forth in Section 4.2 above, then, notwithstanding the provisions of Section 5.4 below, the General Partner shall advance funds to the Partnership in an amount equal
to the funds then required to conduct such operations but in no event more than the total amount of the Aggregate Subscription remaining unpaid. With respect to any such advances, the General Partner shall receive no interest thereon and no
financing charges will be levied by the General Partner in connection therewith. The General Partner shall be repaid out of the Capital Subscription installments thereafter paid into the capital of the Partnership when due. 
  
 4.4 Additional Assessments required by the General Partner pursuant to
Section 5.3 of this Agreement will be payable in cash on such date as the General Partner may set in its written notice, but in no event will such assessments be due earlier than thirty (30) days after the date of mailing of the notice. Notice of
the General Partner’s call for Additional Assessments shall specify the amount required, the manner in which the additional funds will be expended, the date on which such amounts are payable, and the consequences of non-payment. The General
Partner will not be required to accept late payments of such amounts, but it may in its discretion do so. 
  

 A-9 

 4.5 The General Partner will contribute to the capital of the Partnership amounts equal to the total of
all costs paid by the Partnership that are charged to the General Partner’s account as such costs are incurred. 
  
 ARTICLE V 
 Deposit and Use of Capital Contributions and 
 Other Partnership Funds 
  
 5.1 Until required in the conduct of the Partnership’s business, Partnership funds, including, but not limited to, Capital Contributions, Partnership
Revenue and proceeds of borrowings by the Partnership, will be deposited, with or without interest, in one or more bank accounts of the Partnership in a bank or banks selected by the General Partner or invested in short-term United States government
securities, money market funds, bank certificates of deposit or commercial paper rated as “A1” or “P1” as the General Partner, in its sole discretion, deems advisable. Any interest or other income generated by such deposits or
investments will be for the Partnership’s account. Except for Capital Contributions, Partnership funds from any of the various sources mentioned above may be commingled with other Partnership funds and with the funds of the General Partner and
may be withdrawn, expended and distributed as authorized by the terms and provisions of this Agreement. 
  
 5.2 The Capital Contributions of the Limited Partners will be expended for costs incurred by the Partnership that, in accordance with the terms of this
Agreement, are properly chargeable to the Limited Partners’ accounts. 
  
 5.3 After the General Partner’s Minimum Capital Contribution has been fully expended, if the Aggregate Subscription has all been fully expended or committed and additional funds are required in order to pay
Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of productive properties which are chargeable to the Limited Partners, the General Partner may, but shall not be required to, make one or more calls for Additional
Assessments from Limited Partners pursuant to Section 4.4; provided, however, that the aggregate amount of Additional Assessments called of the Limited Partners may not exceed $100 per Unit. The Limited Partners who do not respond will participate
in production, if any, obtained from the aggregate Additional Assessments paid into the Partnership. However, the amount of the unpaid Additional Assessment shall bear interest at the annual rate equal to two (2) percentage points in excess of the
prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time to time, until paid. The Partnership will have a lien on the defaulting Limited Partner’s interest in the Partnership and
the General Partner may apply Partnership Revenue otherwise available for distribution to the defaulting Limited Partner until an amount equal to the unpaid Additional Assessment and interest is received. Furthermore, the General Partner may satisfy
such lien by proceeding with legal action to enforce the lien and the defaulting Limited Partner shall pay all expenses of collection, including interest, court costs and a reasonable attorney’s fee. 
  
 5.4 After the General Partner’s Minimum Capital Contribution has been
fully expended, the General Partner may cause the Partnership to borrow funds for the purpose of paying Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of productive properties, which borrowings may be secured
by interests in the Partnership Properties and will be repaid, including interest accruing thereon, out of Partnership Revenue allocable to the accounts of the Partners on whose behalf the proceeds of such borrowings are expended. The General
Partner may, but is not required to, advance funds to the Partnership for the same purposes for which Partnership borrowings are authorized by this Section 5.4. With respect to any such advances, the General Partner shall receive interest in an
amount equal to the lesser of the interest which would be charged to the Partnership by unrelated banks on comparable loans for the same purpose or the General Partner’s interest cost with respect to such loan, where it borrows the same. No
financing charges will be levied by the General Partner in connection with any such loan. If Partnership borrowings secured by interests in the Partnership Properties and repayable 

  

 A-10 

 
out of Partnership Revenue cannot be arranged on a basis which, in the opinion of the General Partner, is fair and reasonable, and the entire sum required to
pay costs of the type referred to above is not available from Partnership Revenue, the Partnership may elect not to drill or participate in the drilling of a well or the General Partner may dispose of the Partnership Properties upon which such
operations were to be conducted by sale (subject to any other applicable provisions of this Agreement), farm-out or abandonment. 
  
 5.5 The General Partner may utilize Partnership Revenue allocable to the respective accounts of the Partners to pay any Partnership costs and expenses
properly chargeable to the accounts of such Partners. 
  
 5.6 With
respect to any Partnership activity and subject to the restrictions set forth in Sections 5.3 and 5.4 above, it shall be in the sole discretion of the General Partner whether to call for Additional Assessments, arrange for borrowings on behalf of
the Partners, utilize Partnership Revenue or sell (subject to any other applicable provisions of this Agreement), farm-out or abandon Partnership Properties. 
  
 5.7 The Partnership Properties and production therefrom may be pledged, mortgaged or otherwise encumbered as security for borrowings by the Partnership
authorized by Section 5.4 above, provided that the holder of indebtedness arising by virtue of such borrowings may not have or acquire, at any time as a result of making any such loans, any direct or indirect interest in the profits, capital or
property of the Partnership other than as a secured creditor. 
  
 ARTICLE VI 
 Sharing of Costs, Capital Accounts and 
 Allocation of Charges and Income 
  
 6.1 All costs of organizing the Partnership and offering Units therein will be paid by the General Partner. All costs incurred in the offering and syndication of any drilling or income program formed by UPC or UNIT
and its affiliates during 2005 in which the Partnership participates as a co-general partner will also be paid by the General Partner. 
  
 6.2 All other Partnership costs and expenses will be charged 99% to the accounts of the Limited Partners and 1% to the account of the General Partner
until such time as the Aggregate Subscription has been fully expended. Thereafter and until the General Partner’s Minimum Capital Contribution has been fully expended, all of such costs and expenses will be charged to the General Partner. After
the General Partner’s Minimum Capital Contribution has been fully expended, such costs and expenses will be charged to the respective accounts of the General Partner and the Limited Partners on the basis of their respective Percentages.

  
 6.3 All Partnership Revenues will be allocated between the
General Partner and the Limited Partners on the basis of their respective Percentages. 
  
 6.4 Partnership costs, expenses and Revenues which are charged and allocated to the Limited Partners shall be charged and allocated to their respective accounts in the proportion the Units of each Limited Partner bear
to the total number of outstanding Units. 
  

 A-11 

 6.5 Capital accounts shall be established and maintained for each Partner in accordance with tax
accounting principles and with valid regulations issued by the U.S. Treasury Department under subsection 704(b) (the “704 Regulations”) of the Internal Revenue Code of 1986, as amended (the “Code”). To the extent that tax
accounting principles and the 704 Regulations may conflict, the latter shall control. In connection with the establishment and maintenance of such capital accounts, the following provisions shall apply: 
  
 (a) Each Partner’s capital account shall be (i)
increased by the amount of money contributed by him or her to the Partnership, the fair market value of property contributed by him or her to the Partnership (net of liabilities securing such contributed property that the Partnership is considered
to assume or take subject to under section 752 of the Code) and allocations to him or her of Partnership income and gain (except to the extent such income or gain has previously been reflected in his or her capital account by adjustments thereto)
and (ii) decreased by the amount of money distributed to him or her by the Partnership, the fair market value of property distributed to him or her by the Partnership (net of liabilities securing such distributed property that such Partner is
considered to assume or take subject to under section 752 of the Code) and allocations to him or her of Partnership loss, deduction (except to the extent such loss or deduction has previously been reflected in his or her capital account by
adjustments thereto) and expenditures described in section 705(a)(2)(B) of the Code. 
  
 (b) In the event Partnership Property is distributed to a Partner, then, before the capital account of such Partner is adjusted as
required by subsection (a) of this Section 6.5, the capital accounts of the Partners shall be adjusted to reflect the manner in which the unrealized income, gain, loss and deduction inherent in such property (that has not been reflected in such
capital accounts previously) would be allocated among the Partners if there were a taxable disposition of such property for its fair market value on the date of distribution. 
  
 (c) If, pursuant to this Agreement, Partnership Property is reflected on the books of the Partnership at a
book value that differs from the adjusted tax basis of such property, then the Partners’ capital accounts shall be adjusted in accordance with the 704 Regulations for allocations to the Partners of depreciation, depletion, amortization, and
gain or loss, as computed for book purposes, with respect to such property. 
  
 (d) The Partners’ capital accounts shall be adjusted for depletion and gain or loss with respect to the Partnership’s oil or gas properties in whichever of the following manners the General Partner
determines is in the best interests of the Partners: 
  
 (i) the Partners’ capital accounts shall be reduced by a simulated depletion allowance computed on each oil or gas property using either the cost depletion method or the percentage depletion method (without regard to the limitations
under the Code which could apply to less than all Partners); provided, however, that the choice between the cost depletion method and the simulated depletion method shall be made on a property-by-property basis in the first taxable year of the
Partnership for which such choice is relevant for an oil or gas property, and such choice shall be binding for all Partnership taxable years during which such oil or gas property is held by the Partnership. Such reductions for depletion shall not
exceed the aggregate adjusted basis allocated to the Partners with respect to such oil or gas property. Such reductions for depletion shall be allocated among the Partners’ capital accounts in the same proportions as the adjusted basis in the
particular property is allocated to each Partner. Upon the taxable disposition of an oil or gas property by the Partnership, the Partnership’s simulated gain or loss shall be determined by subtracting its simulated adjusted basis (aggregate
adjusted tax basis of the Partners less simulated depletion allowances) in such property from the amount realized on such disposition and the Partners’ capital accounts shall be increased or reduced, as the case may be, by the amount of the
simulated gain or loss on such disposition in proportion to the Partners’ allocable shares of the total amount realized on such disposition, or 
  
 (ii) the Partnership shall reduce the capital account of each Partner in an amount equal to such Partner’s depletion allowance with
respect to each oil or gas property of the Partnership (for the Partner’s taxable year that ends within the Partnership’s taxable year), but such reductions for depletion shall not exceed the adjusted basis allocated to such 

  

 A-12 

 
Partner with respect to such property. Upon the taxable disposition of an oil or gas property by the Partnership, the capital account of each Partner shall
be reduced or increased, as the case may be, by the amount of the difference between such Partner’s allocable share of the total amount realized on such disposition and such Partner’s remaining adjusted tax basis in such property.

  
 (e) For purposes of determining the capital
account balance of any Partner as of the end of any Partnership taxable year for purposes of Subsection 6.6(f) hereof, such Partner’s capital account shall be reduced by: 
  
 (i) adjustments that, as of the end of such year, reasonably are expected to be made to such Partner’s
capital account pursuant to paragraph (b)(2)(iv)(k) of the 704 Regulations for depletion allowances with respect to oil and gas properties of the Partnership, 
  

(ii) allocations of loss and deduction that, as of the end of such year, reasonably are expected to be made to such Partner pursuant to
Code section 704(e)(2), Code section 706(d), and paragraph (b)(2)(ii) of section 1.751-1 of regulations promulgated under the Code, and 
  
 (iii) distributions that, as of the end of such year, reasonably are expected to be made to such Partner to the extent they exceed
offsetting increases to such Partner’s capital account that reasonably are expected to occur during (or prior to) the Partnership taxable years in which such distributions reasonably are expected to be made. 
  
 6.6 With respect to the various allocations of Partnership income, gain,
loss, deduction and credit for federal income tax purposes, it is hereby agreed as follows: 
  
 (a) To the extent permitted by law, all charges, deductions and losses shall be allocated for federal income tax purposes in the same
manner as the costs in respect of which such charges, deductions and losses are charged to the respective accounts of the Partners. The Partners bearing the costs shall be entitled to the deductions (including, without limitation, cost recovery
allowances, depreciation and cost depletion) and credits that are attributable to such costs. 
  
 (b) The Partnership shall allocate to each Partner his or her portion of the adjusted basis in each depletable Partnership Property as
required by Section 613A(c)(7)(D) of the Code based upon the interest of said Partner in the capital of the Partnership as of the time of the acquisition of such Partnership Property. To the extent permitted by the Code, such allocation shall be
based upon said Partner’s interest (i) in the Partnership capital used to acquire the property, or (ii) in the adjusted basis of the property if it is contributed to the Partnership. If such allocation of basis is not permitted under the Code,
then basis will be allocated in the permissible manner which the General Partner deems will most closely achieve the result intended above. 
  
 (c) Partnership Revenue shall be allocated for federal income tax purposes in the same manner as it is allocated to the respective
accounts of the Partners pursuant to Sections 6.3 and 6.4 above. 
  
 (d) Depreciation or cost recovery allowance recapture and recapture of intangible drilling and development costs, if any, due as a result of sales or dispositions of assets shall be allocated in the same proportion
that the depreciation, cost recovery allowances or intangible drilling and development costs being recaptured were allocated. 
  
 (e) Notwithstanding anything to the contrary stated herein, 
  
 (i) there shall be allocated first to other Limited Partners and then to the General Partner any item of
loss, deduction, credit or allowance that, but for this Subsection 6.6(e), would have been allocated to any Limited Partner that is not obligated to restore 

  

 A-13 

 
any deficit balance in such Limited Partner’s capital account and would have thereupon caused or increased a deficit balance in such Limited
Partner’s capital account as of the end of the Partnership’s taxable year to which such allocation related (after taking into consideration the numbered items specified in Subsection 6.5(e) hereof); 
  
 (ii) any Limited Partner that is not obligated to restore
any deficit balance in such Limited Partner’s capital account who unexpectedly receives an adjustment, allocation or distribution specified in Subsection 6.5(e) hereof shall be allocated items of income and gain in an amount and manner
sufficient to eliminate such deficit balance as quickly as possible; and 
  
 (iii) in the event any allocations of loss, deduction, credit or allowance are made to a Limited Partner or the General Partner pursuant to clause (i) of this Subsection 6.6(e), then such Limited Partner and/or the
General Partner shall be subsequently allocated all items of income and gain pro rata as they were allocated the item(s) of loss, deduction, credit or allowance under such clause (i) until the aggregate amount of such allocations of income and gain
is equal to the aggregate amount of any such allocations of loss, deduction, credit or allowance allocated to such Partner(s) pursuant to clause (i) of this Subsection 6.6(e). 
  
 (f) Notwithstanding any other provision of this Agreement, if, under any provision of this Agreement, the
capital account of any Partner is adjusted to reflect the difference between the basis to the Partnership of Partnership Property and such property’s fair market value, then all items of income, gain, loss and deduction with respect to such
property shall be allocated among the Partners so as to take account of the variation between the basis of such property and its fair market value at the time of the adjustment to such Partner’s capital account in accordance with the
requirements of subsection 704(c) of the Code, or in the same manner as provided under subsection 704(c) of the Code. 
  
 6.7 Notwithstanding anything to the contrary that may be expressed or implied in this Agreement, the interest of the General Partner in each material item
of Partnership income, gain, loss, deduction or credit shall be equal to at least one percent of each such item at all times during the existence of the Partnership. In determining the General Partner’s interest in such items, Units owned by
the General Partner shall not be taken into account. 
  
 6.8
Except as provided in subsections (a) through (d) of this Section 6.8, in the case of a change in a Partner’s interest in the Partnership during a taxable year of the Partnership, all Partnership income, gain, loss, deduction or credit
allocable to the Partners shall be allocated to the persons who were Partners during the period to which such item is attributable in accordance with the Partners’ interests in the Partnership during such period regardless of when such item is
paid or received by the Partnership. 
  
 (a) With
respect to certain “allocable cash basis items” (as such term is defined in the Code) of Partnership Revenue, gain, loss, deduction or credit, if, during any taxable year of the Partnership there is change in any Partner’s interest in
the Partnership, then, except to the extent provided in regulations prescribed under Section 706 of the Code, each Partner’s allocable share of any “allocable cash basis item” shall be determined by (i) assigning the appropriate
portion of each such item to each day in the period to which it is attributable, and (ii) allocating the portion assigned to any such day among the Partners in proportion to their interests in the Partnership at the close of such day. 
  
 (b) If, by adhering to the method of allocation described in
the immediately preceding subsection of this Section 6.8, a portion of any “allocable cash basis item” is attributable to any period before the beginning of the Partnership taxable year in which such item is received or paid, such portion
shall be (i) assigned to the first day of the taxable year in which it is received or paid, and (ii) allocated among the persons who were Partners in the Partnership during the period to which such portion is attributable in accordance with their
interests in the Partnership during such period. 
  

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 (c) If any portion of any “allocable cash basis item” paid or received by the
Partnership in a taxable year is attributable to a period after the close of that taxable year, such portion shall be (i) assigned to the last day of the taxable year in which it is paid or received, and (ii) allocated among the persons who are
Partners in proportion to their interests in the Partnership at the close of such day. 
  
 (d) If any deduction is allocated to a person with respect to an “allocable cash basis item” attributable to a period before the
beginning of the Partnership taxable year and such person is not a Partner of the Partnership on the first day of the Partnership taxable year, such deduction shall be capitalized by the Partnership and treated in the manner provided for in Section
755 of the Code. 
  
 ARTICLE VII 
 Fiscal Year, Accountings and Reports 
  
 7.1 Unless the Code requires otherwise, the fiscal year of the Partnership will be the calendar year and the books of the Partnership will be kept in
accordance with usual and customary accounting practices on the accrual method. 
  
 7.2 Within sixty (60) days after the end of each quarter of each Partnership fiscal year, each person who was a Limited Partner during such period will be furnished a report setting forth the source and disposition of
Partnership funds during the quarter. 
  
 7.3 Not later than the
end of the fiscal year in which all Partnership Wells are drilled and completed, and sufficient production history has been obtained on Partnership Wells to evaluate properly the reserves attributable thereto, the General Partner will make an
evaluation of Partnership Properties as of the last day of such fiscal year. The report shall include an estimate of the total oil and gas proven reserves of the Partnership and the dollar value thereof and the value of the Limited Partner’s
interest in such reserve value. It shall also contain an estimate of the present worth of the reserves. Each Limited Partner will receive a summary statement of such report reflecting the Limited Partners’ interest in such reserve value.

  
 ARTICLE VIII 
 Tax Returns and Elections 
  
 8.1 Unless the Code requires otherwise, the General Partner will cause the Partnership to elect the calendar year as its taxable year and will timely file
all Partnership income tax returns required to be filed by the jurisdictions in which the Partnership conducts business or derives income. By March 15 of each year or as soon thereafter as practicable, the General Partner will furnish all available
information necessary for inclusion in the income tax returns of each person who was a Limited Partner during the prior fiscal year. The General Partner shall be the “Tax Matters Partner” for the Partnership pursuant to the provisions of
Section 6231 of the Code subject to the provisions of Section 10.22 below. 
  
 8.2 The Partnership will elect to deduct intangible drilling and development costs currently as an expense for income tax purposes and will elect to use the available depreciation method which, in the General
Partner’s judgment, is in the best interest of the Partners. 
  
 8.3 The General Partner shall have the right in its sole discretion at any time to make or not to make such other elections as are authorized or permitted by any law or regulation for income tax purposes (including any election under
Section 754 of the Code). 
  

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 ARTICLE IX 
 Distributions 
  
 9.1 The
Partnership’s available cash will be distributed to the Limited Partners and the General Partner in the same proportions that Partnership Revenue has been allocated to them after giving effect to previous distributions and to portions of such
revenue theretofore used or retained to pay costs incurred or expected to be incurred in conducting Partnership operations or to repay borrowings theretofore or expected to be thereafter obtained by the Partnership. Within forty-five (45) days after
the end of each calendar quarter, the General Partner will determine the amount of cash available for distribution to the Limited Partners and will distribute such amount, if any, as promptly thereafter as reasonably possible. Distributions of cash
to the General Partner may be at any time the General Partner determines there is cash available therefor. The General Partner’s determination of the cash available for distribution will be conclusive and binding upon all Partners. All
Partnership funds distributed to the Limited Partners shall be distributed to the persons who were record holders of Units on the day on which the distribution is made. 
  
 ARTICLE X 
 Rights, Duties and Obligations of the General Partner 
  
 10.1 Subject to the limitations of this Agreement, the General Partner will have full, exclusive and complete discretion in the management and control of the business of the Partnership and will make all decisions affecting its business and
affairs or the Partnership Properties. The General Partner will have, subject to the provisions of this Article X, full power and authority to take any action described in Article III above and execute and deliver in the name of and on behalf of the
Partnership such documents or instruments as the General Partner deems appropriate for the conduct of Partnership business. No person, firm or corporation dealing with the Partnership will be required to inquire into the authority of the General
Partner to take any action or make any decision. 
  
 10.2 The
General Partner will perform the duties imposed upon it under this Agreement in an efficient and businesslike manner with due caution and in accordance with established practices of the oil and gas industry, but the General Partner shall not be
liable, responsible or accountable in damages or otherwise to the Partnership or any of the Partners for, and the Partnership shall indemnify, defend against and save harmless the General Partner, from any expense (including attorneys’ fees),
loss or damage incurred by reason of any act or omission performed or omitted in good faith on behalf of the Partnership or the Partners, and in a manner reasonably believed by the General Partner to be within the scope of the authority granted by
this Agreement and in the best interests of the Partnership or the Partners, provided that the General Partner is not guilty of gross negligence or willful misconduct with respect to such acts or omissions, and further provided that the satisfaction
of any indemnification and any saving harmless shall be from and limited to Partnership assets including insurance proceeds, if any, and no Partner shall have any personal liability on account thereof. For purposes of this Section 10.2 only, the
term General Partner includes the General Partner, affiliates of the General Partner and any officer, director or employee of the General Partner or any of its affiliates such that all of such parties are covered by the indemnities provided herein.

  
 10.3 The General Partner will utilize its organization and
employees and will hire outside consultants for the Partnership as necessary in order to provide experienced, qualified and competent personnel to conduct the Partnership’s business. With certain limited exceptions it is the intent of the
Partners that the Partnership participate as a co-general partner of any oil and gas drilling or income programs, or both, formed by the General Partner or UNIT for third party investors during 2005 and to participate on a proportionate working
interest basis in each producing oil and gas lease acquired and in the drilling of each oil and gas well commenced by the General Partner or UNIT for its own account during the period from the later of January 1, 2005 or the Effective Date through
December 31, 2005 (except for wells, if any, (i) drilled outside of the 48 contiguous United States; (ii) drilled as part of 

  

 A-16 

 
secondary or tertiary recovery operations which were in existence prior to the formation of the Partnership; (iii) drilled by third parties under farm-out or
similar arrangements with the General Partner or UNIT or whereby the General Partner or UNIT may be entitled to an overriding royalty, reversionary or other similar interest in the production from such wells but is not obligated to pay any of the
Drilling Costs thereof; (iv) acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies; or (v) with respect to which the General Partner does not
believe that the potential economic return therefrom justifies the costs of participation by the Partnership). 
  
 10.4 The General Partner, UNIT or any affiliate thereof will transfer to the Partnership interests in oil and gas properties comprising the spacing unit
on which a Partnership Well is located or is to be drilled for the separate account of the Partnership, provided that no broker’s commissions or fees of a similar nature will be paid in connection with any such transfer and the consideration
paid by the Partnership will be equal to the Leasehold Acquisition Costs of the property so transferred. If the size of a spacing unit on which a Partnership Well is located is ever reduced or increased well density is permitted thereon, the
Partnership will not be entitled to any reimbursement or recoupment of any portion of the Leasehold Acquisition Costs paid with respect thereto notwithstanding the provisions of Section 10.7 below. 
  
 10.5 With respect to certain transactions involving Partnership Properties,
it is hereby agreed as follows: 
  
 (a) A sale,
transfer or conveyance by the General Partner or any affiliate of less than its entire interest in such property is prohibited unless (i) the interest retained by the General Partner or its affiliate is a proportionate working interest, (ii) the
respective obligations of the General Partner or its affiliate and the Partnership are substantially the same proportionately as those of the General Partner or its affiliate at the time it acquired the property and (iii) the Partnership’s
interest in revenues will not be less than the proportionate interest therein of the General Partner or its affiliate when it acquired the property. The General Partner or its affiliate may retain the remaining interest for its own account or it may
sell, transfer, farm-out or otherwise convey all or a portion of such remaining interest to non-affiliated industry members. In connection with any such sale, transfer, farm-out or other conveyance of such interest to non-affiliated industry
members, which may occur either before or after the transfer of the interests in the same properties to the Partnership, the General Partner or its affiliate may realize a profit on the interests or may be carried to some extent with respect to its
cost obligations in connection with any drilling on such properties and any such profit or interest will be strictly for the account of the General Partner and the Partnership will have no claim with respect thereto. 
  
 (b) The General Partner or its affiliates may not retain any
overrides or other burdens on property conveyed to the Partnership (other than overriding royalty interests granted to geologists and other persons employed or retained by the General Partner or its affiliates). 
  
 10.6 The General Partner will cause the Partnership Properties to be acquired
in accordance with the customs of the oil and gas industry in the area. The Partnership will be required to do only such title work with respect to its oil and gas properties as the General Partner in its sole judgment deems appropriate in light of
the area, any applicable drilling or expiration dates and any other material factors. 
  
 10.7 Partnership Properties shall be transferred to the Partnership after the decision to acquire a productive property or the commitment to drill a Partnership Well thereon has been made. The Partnership shall
acquire interests in only those properties of the General Partner or UNIT which comprise the spacing unit on which the Partnership Well is drilled or on which a producing Partnership Well is located. If a spacing unit on which a Partnership Well is
drilled or located is ever reduced, or any subsequent well in which the Partnership has no interest is drilled thereon, the Partnership will have no interest in any such subsequent or additional wells drilled on properties which were a part of the
original spacing unit unless any such additional well is commenced during 2005 or is drilled by a drilling or 
  

 A-17 

 
income program of which the Partnership is a partner. Likewise if UNIT, UPC or any affiliate, including any oil and gas partnership subsequently formed for
investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries, acquires additional interests in Partnership Wells after 2005 the Partnership generally will not be entitled to participate in the acquisition
of such additional interests. In addition, if a Partnership Well drilled on a spacing unit is dry or abandoned, the Partnership will not have an interest in any subsequent or additional well drilled on the spacing unit unless it is commenced during
2005 or is drilled by a drilling or income program of which the Partnership is a partner. 
  
 10.8 The General Partner, UNIT or its affiliates will either conduct the Partnership’s drilling and production operations and operate each Partnership Well or arrange for a third party operator to conduct such
operations. The General Partner will, on behalf of the Partnership, enter into appropriate operating agreements with other owners of Partnership Wells authorizing the General Partner, its affiliates or a third party operator to conduct such
operations. The Partnership will take such action in connection with operations pursuant to said operating agreements as the General Partner, in its sole discretion, deems appropriate and in the best interests of the Partnership, and the decision of
the General Partner with respect thereto will be binding upon the Partnership. 
  
 10.9 The General Partner will cause the Partnership to plug and abandon its dry holes and abandoned wells in accordance with rules and regulations of the governmental regulatory body having jurisdiction. 

 
 10.10 The General Partner may pool or unitize Partnership Properties with
other oil and gas properties when such pooling or unitization is required by a governmental regulatory body, when well spacing as determined by any such body requires such pooling or unitization, or when, in the General Partner’s opinion, such
pooling or unitization is in the best interests of the Partnership. 
  
 10.11 The General Partner will have authority to make and enter into contracts for the sale of the Partnership’s share of oil or gas production from Partnership Wells, including contracts for the sale of such production to the General
Partner, UNIT or its affiliates; provided, however, that the production purchased by the General Partner, UNIT or any of its affiliates will be for prices which are not less than the highest posted price (in the case of crude oil production) or
prevailing price (in the case of natural gas production) in the same field or area. 
  
 10.12 The General Partner will use its best efforts to procure and maintain for the Partnership, and at its expense, such insurance coverage with responsible companies as may be reasonably available for such premium
costs as would not be considered to be unreasonably high or prohibitive with respect to each item of coverage and as the General Partner considers necessary for the protection of the Partnership and the Partners. The coverage will be in such amounts
and will cover such risks as the General Partner believes warranted by the operations conducted hereunder. Such risks may include but will not necessarily be limited to public liability and automobile liability, each covering bodily injury, death
and property damage, workmen’s compensation and employer’s liability insurance and blowout and control of well insurance. 
  
 10.13 In order to conduct properly the business of the Partnership, and in order to keep the Partners properly informed, the General Partner will:

  
 (a) maintain adequate records and files
identifying the Partnership Properties and containing all pertinent information in regard thereto that is obtained or developed pursuant to this Agreement; 
  
 (b) maintain a complete and accurate record of the acquisition and disposition of each Partnership Property; 
  
  

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 (c) maintain appropriate books and records reflecting the Partnership’s revenue and
expense and each Partner’s participation therein; 
  
 (d) maintain a capital account for each Partner with appropriate records as necessary in order to reflect each Partner’s interest in the Partnership and furnish required tax information; and 
  
 (e) keep the Limited Partners informed by means of written
reports on the acquisition of Partnership Properties and the progress of the business and operations of the Partnership, which reports will be rendered semi-annually and at such more frequent intervals during the progress of Partnership operations
as the General Partner deems appropriate. 
  
 10.14 The General
Partner, UNIT and the officers, directors, employees and affiliates thereof may own, purchase or otherwise acquire and deal in oil and gas properties, drill wells, conduct operations and otherwise engage in any aspect of the oil and gas business,
either for their own accounts or for the accounts of others. Each Limited Partner hereby agrees that engaging in any activity permitted by this Section 10.14 will not be considered a breach of any duty that the General Partner, UNIT or the officers,
directors, employees and affiliates thereof may have to the Partnership or the Limited Partners, and that the Partnership and the Limited Partners will not have any interest in any properties acquired or profits which may be realized with respect to
any such activity. 
  
 10.15 Subject to Section 12.1, without the
prior consent of Limited Partners holding a majority of the outstanding Units, the General Partner will not (i) make, execute or deliver any assignment for the benefit of the Partnership’s creditors; or (ii) contract to sell all or
substantially all of the Partnership Properties (except as permitted by Sections 10.23 and 16.4(b)). 
  
 10.16 In contracting for services to and insurance coverage for the Partnership and its activities and operations, and in acquiring material, equipment
and personal property on behalf of the Partnership, the General Partner will use its best efforts to obtain such services, insurance, material, equipment and personal property at prices no less favorable than those normally charged in the same or in
comparable geographic areas by non-affiliated persons or companies dealing at arm’s length. No rebates, concessions or compensation of a similar nature will be paid to the General Partner by the person or company supplying such services,
insurance, material, equipment and personal property. 
  
 10.17
The General Partner, UNIT or its affiliates are authorized to provide equipment, materials and services to the Partnership in connection with the conduct of its operations, provided, that the terms of any contracts between the Partnership and the
General Partner, UNIT or any affiliates, or the officers, directors, employees and affiliates thereof must be no less favorable to the Partnership than those of comparable contracts entered into, and will be at prices not in excess of those charged
in the same geographical area by non-affiliated persons or companies dealing at arm’s length. Any such contracts for services must be in writing precisely describing the services to be rendered and all compensation to be paid. 
  
 10.18 The General Partner may cause the Partnership to hold Partnership
Properties in the Partnership’s name, or in the name of the General Partner, UNIT, any affiliates thereof or some third party as nominee for the Partnership. If record title to a Partnership Property is to be held permanently in the name of a
nominee, such nominee arrangement will be evidenced and documented by a nominee agreement identifying the Partnership Properties so held and disclaiming any beneficial interest therein by the nominee. 
  
 10.19 The General Partner will be generally liable for the debts and
obligations of the Partnership, provided that any claims against the Partnership shall be satisfied first out of the assets of the Partnership and only thereafter out of the separate assets of the General Partner. 
  
 10.20 The Partnership may not make any loans to the General Partner, UNIT or
any of its affiliates. 
  

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 10.21 The General Partner will use its best efforts at all times to maintain its net worth at a level
that is sufficient to insure that the Partnership will be classified for federal income tax purposes as a partnership, rather than as an association taxable as a corporation, on account of the net worth of the General Partner. 
  
 10.22 The Tax Matters Partner designated in Section 8.1 above is authorized
to engage legal counsel and accountants and to incur expense on behalf of the Partnership in contesting, challenging and defending against any audits, assessments and administrative or judicial proceedings conducted or participated in by the
Internal Revenue Service with respect to the Partnership’s operations and affairs. 
  
 10.23 At any time two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner may, without the vote, consent or
approval of the Limited Partners, cause all or substantially all of the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or consolidated with, another partnership or a
corporation, trust or other entity for the purpose of combining the assets of two or more of the oil and gas partnerships formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries; provided,
however, that the valuation of the oil and gas properties and other assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a manner which the General Partner and UNIT
believe is fair and equitable to the Limited Partners. As a consequence of any such transfer or combination, the Partnership shall be dissolved and terminated pursuant to Article XVI hereof and the Limited Partners shall receive partnership
interests, stock or other equity interests in the transferee or resulting entity. 
  
 ARTICLE XI 
 Compensation and Reimbursements 
  
 11.1 For the General Partner’s services performed as operator of
productive Partnership Wells located on Partnership Properties and as operator during the drilling of Partnership Wells, the Partnership will compensate the General Partner at rates no higher than those normally charged in the same or a comparable
geographic area by non-affiliated persons or companies dealing at arm’s length. The General Partner will not receive compensation for such services performed in connection with the operation of Partnership Wells operated by third party
operators, but such third party operators will be compensated as provided in the operating agreements in effect with respect to such wells and the Partnership will pay its proportionate share of such compensation. 
  
 11.2 The General Partner will be reimbursed by the Partnership out of
Partnership Revenues for that portion of its general and administrative overhead expense that is attributable to its conduct of the actual and necessary business, affairs and operations of the Partnership. The General Partner’s general and
administrative overhead expenses will be determined in accordance with industry practices. The allocable costs and expenses will include all customary and routine legal, accounting, geological, engineering, travel, office rent, telephone,
secretarial, salaries, data processing, word processing and other incidental reasonable expenses necessary to the conduct of the Partnership’s business and generated by the General Partner or allocated to it by UNIT, but will not include filing
fees, commissions, professional fees, printing costs and other expenses incurred in forming the Partnership or offering interests therein. Also excluded will be any general and administrative overhead expense of the General Partner or UNIT which may
be attributable to its services as an operator of Partnership Wells for which it receives compensation pursuant to Section 11.1 above. The portion of the General Partner’s general and administrative overhead expense to be reimbursed by the
Partnership with respect to any particular period will be determined by allocating to the Partnership that portion of the General Partner’s total general and administrative overhead expense incurred during such period which is equal to the
ratio of the Partnership’s total expenditures compared to the total expenditures by the General Partner for its own account. The portion of such general and administrative overhead expense reimbursement which is 
  

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charged to the Limited Partners may not exceed an amount equal to 3% of the Aggregate Subscription during the first 12 months of the Partnership’s
operations, and in each succeeding twelve-month period, the lesser of (a) 2% of the Aggregate Subscription and (b) 10% of the total Partnership Revenue realized in such twelve-month period. Administrative expenses incurred directly by the
Partnership, or incurred by the General Partner on behalf of the Partnership and reimbursable to the General Partner, such as legal, accounting, auditing, reporting, engineering, mailing and other such fees, costs and expenses are not to be deemed a
part of the general and administrative expense of the General Partner which is to be reimbursed pursuant to this Section 11.2 and the amounts thereof will not be subject to the limitations described in the preceding sentence. 
  
 ARTICLE XII 
 Rights and Obligations of Limited Partners 
  
 12.1 The Limited Partners, in their capacity as such, cannot transact any business for the Partnership or take part in the control of its business or
management of its affairs. Limited Partners will have no power to execute any agreements on behalf of, or otherwise bind or commit, the Partnership. They may give consents and approvals as herein provided and exercise the rights and powers granted
to them in this Agreement, it being understood that the exercise of such rights and powers will be deemed to be matters affecting the basic structure of the Partnership and not the exercise of control over its business; provided, however, that
exercise of any of the rights and powers granted to the Limited Partners in Sections 10.15, 12.3, 14.1, 16.1 and 18.1 will not be authorized or effective unless prior to the exercise thereof the General Partner is furnished an opinion of counsel for
the Partnership or an order or judgment of any court of competent jurisdiction to the effect that the exercise of such rights or powers (i) will not be deemed to evidence that the Limited Partners are taking part in the control of or management of
the Partnership’s business and affairs, (ii) will not result in the loss of any Limited Partner’s limited liability and (iii) will not result in the Partnership being classified as an association taxable as a corporation for federal income
tax purposes. 
  
 12.2 The Limited Partners will not be personally
liable for any debts or losses of the Partnership. Except as otherwise specifically provided herein, no Partner will be responsible for losses of any other Partners. 
  
 12.3 Except as otherwise provided in this Agreement, no Limited Partner will be entitled to the return of his contribution.
Distributions of Partnership assets pursuant to this Agreement may be considered and treated as returns of contributions if so designated by law or, subject to Section 12.1, by agreement of the General Partner and Limited Partners holding a majority
of the outstanding Units. The value of a Limited Partner’s undistributed contribution determined for the purposes of Section 39 of the Act at any point in time shall be his or her percentage of the amount of the Partnership’s stated
capital allocated to the Limited Partners as reflected in the financial statements of the Partnership as of such point in time. No Partner will receive any interest on his or her contributions and no Partner will have any priority over any other
Partner as to the return of contributions. 
  
 ARTICLE XIII

 Transferability of Limited Partner’s Interest 
  
 13.1 Notwithstanding the provisions of Section 13.3, no sale, exchange, transfer or assignment of a Limited Partner’s
interest in the Partnership may be made unless in the opinion of counsel for the Partnership, 
  
 (a) such sale, exchange, transfer or assignment, when added to the total of all other sales, exchanges, transfers or assignments of
interests in the Partnership within the preceding 12 months, would not result in the Partnership being considered to have terminated within the meaning of Section 708 of the Code (provided, however, that this condition may be waived by the General
Partner in its discretion); 
  

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 (b) such sale, exchange, transfer or assignment would not violate, or cause the offering
of the Units to be violative of, the Securities Act of 1933, as amended, or any state securities or “blue sky” laws (including any investor suitability standards) applicable to the Partnership or the interest to be sold, exchanged,
transferred or assigned; and 
  
 (c) such sale,
exchange, transfer or assignment would not cause the Partnership to lose its status as a partnership for federal income tax purposes, and said opinion of counsel is delivered in writing to the Partnership prior to the date of the sale, exchange,
transfer or assignment. 
  
 13.2 In no event shall all or any part
of an interest in the Partnership be assigned or transferred to a minor (except in trust or pursuant to the Uniform Gifts to Minors Act) or an incompetent (except in trust), except by will or intestate succession. 
  
 13.3 Except for transfers or assignments (in trust or otherwise) by a Limited
Partner of all or any part of his or her interest in the Partnership 
  
 (a) to the General Partner, 
  
 (b) to or for the benefit of himself or herself, his or her spouse, or other members of his or her immediate family sharing the same household, 
  
 (c) to a corporation or other entity in which all of the beneficial owners are Limited Partners or assigns
permitted in (a) and (b) above, or 
  
 (d) by the
General Partner to any person who at the time of such transfer is an employee of the General Partner, UNIT or its subsidiaries, no Limited Partner’s Units or any portion thereof may be sold, assigned or transferred except by reason of death or
operation of law. 
  
 13.4 If a Limited Partner dies, his or her
executor, administrator or trustee, or, if he or she is adjudicated incompetent, his or her committee, guardian or conservator, or, if he or she becomes bankrupt, the trustee or receiver of his or her estate, shall have all the rights of a Limited
Partner for the purpose of settling or managing his or her estate and such power as the deceased, incapacitated or bankrupt Limited Partner possessed to assign all or any part of his or her interest and to join with such assignee in satisfying
conditions precedent to such assignee’s becoming a Substituted Limited Partner. 
  
 13.5 The Partnership shall not recognize for any purpose any purported sale, assignment or transfer of all or any fraction of the interest of a Limited Partner in the Partnership, unless the provisions of Section 13.1
shall have been complied with and there shall have been filed with the Partnership a written and dated notification of such sale, assignment or transfer in form satisfactory to the General Partner, executed and acknowledged by both the seller,
assignor or transferor and the purchaser, assignee or transferee and such notification (i) contains the acceptance by the purchaser, assignee or transferee of all of the terms and provisions of this Agreement and (ii) represents that such sale,
assignment or transfer was made in accordance with all applicable laws and regulations. Any sale, assignment or transfer shall be recognized by the Partnership as effective on the date of such notification if the date of such notification is within
thirty (30) days of the date on which such notification is filed with the Partnership, and otherwise shall be recognized as effective on the date such notification is filed with the Partnership. 
  
 13.6 Any Limited Partner who shall assign all of his or her interest in the
Partnership shall cease to be a Limited Partner, except that, unless and until a Substituted Limited Partner is admitted in his or her stead, such assigning Limited Partner shall retain the statutory rights of the assignor of a Limited
Partner’s interest under the Act. 
  

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 13.7 A person who is the assignee of all or any fraction of the interest of a Limited Partner, but does
not become a Substituted Limited Partner and desires to make a further assignment of such interest, shall be subject to all the provisions of this Article XIII to the same extent and in the same manner as any Limited Partner desiring to make an
assignment of his or her interest. 
  
 13.8 No Limited Partner
shall have the right to substitute a purchaser, assignee, transferee, donee, heir, legatee, distributee or other recipient of all or any portion of such Limited Partner’s interest in the Partnership as a Limited Partner in his or her place. Any
such purchaser, assignee, transferee, donee, legatee, distributee or other recipient of an interest in the Partnership shall be admitted to the Partnership as a Substituted Limited Partner only with the consent of the General Partner, which consent
shall be granted or withheld in the sole and absolute discretion of the General Partner and may be arbitrarily withheld, and only by an amendment to this Agreement or the certificate of limited partnership duly executed and recorded in the proper
records of each jurisdiction in which the Partnership owns mineral interests and filed in the proper records of the State of Oklahoma. Any such consent by the General Partner shall be binding and conclusive without the consent of any Limited
Partners and may be evidenced by the execution of the General Partner of an amendment to this Agreement or the certificate of limited partnership, evidencing the admission of such person as a Substituted Limited Partner. 
  
 13.9 No person shall become a Substituted Limited Partner until such person
shall have: 
  
 (a) become a party to, and
adopted all of the terms and conditions of, this Agreement; 
  
 (b) if such person is a corporation, partnership or trust, provided the General Partner with evidence satisfactory to counsel for the Partnership of such person’s authority to become a Limited Partner under the
terms and provisions of this Agreement; and 
  
 (c) paid or agreed to pay the costs and expenses incurred by the Partnership in connection with such person’s becoming a Limited Partner. 
  
 Provided, however, that for the purpose of allocating Partnership Revenue, costs and expenses, a person shall be treated as having become, and as appearing in the records
of the Partnership as, a Substituted Limited Partner on such date as the sale, assignment or transfer was recognized by the Partnership pursuant to Section 13.5. 
  
 13.10 By his or her execution of his or her Subscription Agreement, each Limited Partner represents and warrants to the
General Partner and to the Partnership that his or her acquisition of his or her interest in the Partnership is made as principal for his or her own account for investment purposes only and not with a view to the resale or distribution of such
interest. Each Limited Partner agrees that he or she will not sell, assign or otherwise transfer his or her interest in the Partnership or any fraction thereof unless such interest has been registered under the Securities Act of 1933, as amended, or
such sale, assignment or transfer is exempt from such registration and, in any event, he or she will not so sell, assign or otherwise transfer his or her interest or any fraction thereof to any person who does not similarly represent, warrant and
agree. 
  
 ARTICLE XIV 
 Assignments by the General Partner 
  
 14.1 The General Partner may not sell, assign, transfer or otherwise dispose of its interest in the Partnership except with the prior consent, subject to
Section 12.1, of Limited Partners holding a majority of the outstanding Units; provided that a sale, assignment or transfer may be effective without such consent if pursuant to a bona fide merger, any other corporate reorganization or a complete
liquidation, pursuant to a sale of all or substantially all of the General Partner’s assets (provided the purchasers of such assets agree to assume the duties and obligations of the General Partner) or a sale or transfer to UNIT or any
affiliates of UNIT. If the Limited Partners’ consent to a proposed transfer is 

  

 A-23 

 
required, the General Partner will, concurrently with the request for such consent, give the Limited Partners written notice identifying the interest to be
transferred, the date on which the transfer is to be effective, the proposed transferee and the substitute General Partner, if any. 
  
 14.2 Sales, assignments and transfers of the interests in the Partnership owned by the General Partner will be subject to, and the assignee will acquire
the assigned interest subject to, all of the terms and provisions of this Agreement. 
  
 14.3 If the Limited Partners’ consent to a transfer of the General Partner’s interest in the Partnership is obtained as above provided, or is not required, the transferee may become a substitute General
Partner hereunder. The substitute General Partner will assume and agree to perform all of the General Partner’s duties and obligations hereunder and the transferring General Partner will, upon making a proper accounting to the substitute
General Partner, be relieved of any further duties or obligations hereunder with respect to Partnership operations thereafter occurring. 
  
 ARTICLE XV 
 Limited Partners’
Right of Presentment 
  
 15.1 After December 31, 2006, each
Limited Partner will have the option, subject to the terms and conditions set forth in this Article XV, to require the General Partner to purchase all (but not less than all) of his or her Units, provided that the option may not be exercised after
the date of any notice that will effect a dissolution and termination of the Partnership pursuant to Article XVI below. Any such exercise shall be effected by written notice thereof delivered to the General Partner. 
  
 15.2 Sales of Limited Partners’ Units pursuant to this Article XV will
be effective, and the purchase price for such interests will be determined, as of the close of business on the last day of the calendar year in which the Limited Partner’s notice exercising his or her option is given, or, at the General
Partner’s election, as of 7:00 o’clock A.M. on the following day. 
  
 15.3 The purchase price to be paid for the Units of any Limited Partner who exercises the option granted in this Article XV will be determined in the following manner. First, future gross revenues expected to be
derived from the production and sale of the proved reserves attributable to Partnership Properties will be estimated, as of the end of the calendar year in which presentment is made, by the independent engineering firm preparing a report on the
reserves of the Partnership, or if no such firm is preparing a report as of the end of the calendar year in which the option is exercised, then by the General Partner. Next, future net revenues will be calculated by deducting anticipated expenses
(including Operating Expenses and other costs that will be incurred in producing and marketing such reserves and any gross production, excise, or other taxes, other than federal income taxes, based on the oil and gas production of the Partnership or
sales thereof) from estimated future gross revenues. The price to be used in calculating future gross revenues as well as the estimates of price and cost escalations to be used in such calculations will be those of such independent engineering firm
or the General Partner, whichever is making the determination. Then the present worth of the future net revenues will be calculated by discounting the estimated future net revenues at that rate per annum which is one (1) percentage point higher than
the prime rate of interest being charged by Bank of Oklahoma, N.A., Tulsa, Oklahoma, or any successor bank, as such prime rate of interest is announced by said bank as of the date such reserves are estimated. This amount will be reduced by an
additional 25% to take into account the uncertainties attendant to the production and sale of oil and gas reserves and other unforeseen contingencies. Estimated salvage value of tangible equipment installed on the Partnership Wells and costs of
plugging and abandoning the productive Partnership Wells, both discounted at the aforementioned rate from the expected date of abandonment, will be considered, and Partnership Properties, if any, which do not have proved reserves attributable to
them but which have not been condemned will be valued at the lower of cost or their then current market value as determined by the aforementioned independent petroleum engineering firm or General Partner, as the case may be. The Partnership’s
cash on hand, prepaid expenses, accounts receivable (less a reasonable reserve for doubtful accounts) and the market value of its 

  

 A-24 

 
other assets as determined by the General Partner will be added to the value of the Partnership Properties thus determined, and the Partnership’s debts,
obligations and other liabilities will be deducted, to arrive at the Partnership’s net asset value for purposes of this Section 15.3. The price to be paid for the Limited Partner’s interest will be his or her proportionate share of such
net asset value less 75% of the amount of any Partnership distributions received by him or her which are attributable to sales of Partnership production since the date as of which the Partnership’s proved reserves are estimated. 
  
 15.4 Within one hundred twenty (120) days after the end of any calendar year
in which a Limited Partner exercises his or her option to require purchase of his or her Units as provided in this Article XV, the General Partner will furnish to such Limited Partner a statement showing the price to be paid for his or her Units and
evidencing that such price has been determined in accordance with the provisions of Section 15.3 above. The statement will show which portion of the proposed purchase price is represented by the value of the proved reserves and by each of the other
classes of Partnership assets and liabilities attributable to the account of the Limited Partner. The Limited Partner will then have thirty (30) days to confirm, by further notice to the General Partner, his or her intention to sell his or her Units
to the General Partner. If the Limited Partner timely confirms his or her intention to sell, the sale will be consummated and the price paid in cash within ten (10) days after such confirmation. The General Partner will not be obligated to purchase
(i) any Units pursuant to such right if such purchase, when added to the total of all other sales, exchanges, transfers or assignments of the Units within the preceding 12 months, would result in the Partnership being considered to have terminated
within the meaning of Section 708 of the Code or would cause the Partnership to lose its status as a partnership for federal income tax purposes, or (ii) in any one calendar year more than 20% of the Units in the Partnership then outstanding. If
less than all of the Units tendered are purchased, the interests purchased will be selected by lot. The Limited Partners whose tendered Units were rejected by reason of the foregoing limitation shall be entitled to priority in the following year.
Contemporaneously with the closing of any such sale, the Limited Partner will execute such certificates or other documents and perform such acts as the General Partner deems necessary to effect the sale and transfer of the liquidating Limited
Partner’s Units to the General Partner and to preserve the limited liability status of the Partnership under the laws of the jurisdictions in which it is doing business. 
  
 15.5 As used in Sections 15.3 and 15.4 above, the term “proved reserves” shall have the meaning ascribed thereto
in Regulation S-X adopted by the Securities and Exchange Commission. 
  
 ARTICLE XVI 
 Termination and Dissolution of Partnership 
  
 16.1 The Partnership will terminate automatically on December 31, 2035, unless prior thereto, subject to Section 12.1 above,
the General Partner or Limited Partners holding a majority of the outstanding Units elect to terminate the Partnership as of an earlier date. In the event of such earlier termination, ninety (90) days’ written notice will be given to all other
Partners. The termination date will be specified in such notice and must be the last day of any calendar month following expiration of the ninety (90) day period unless an earlier date is approved by Limited Partners holding a majority of the
outstanding Units. 
  
 16.2 Upon the dissolution (other than
pursuant to a merger or other corporate reorganization), bankruptcy, legal disability or withdrawal of the General Partner (other than pursuant to Section 14.1 above), the Partnership shall immediately be dissolved and terminated; provided, however,
that nothing in this Agreement shall impair, restrict or limit the rights and powers of the Partners under the laws of the State of Oklahoma and any other jurisdiction in which the Partnership is doing business to reform and reconstitute themselves
as a limited partnership within ninety (90) days following the dissolution of the Partnership either under provisions identical to those set forth herein or under any other provisions. The withdrawal, expulsion, dissolution, death, legal disability,
bankruptcy or insolvency of any Limited Partner will not effect a dissolution or termination of the Partnership. 
  

 A-25 

 16.3 Upon termination of the Partnership by action of the Limited Partners pursuant to Section 16.1
hereof or as a result of an event under Section 16.2 hereof, a party designated by the Limited Partners holding a majority of the outstanding Units will act as Liquidating Trustee. In any other case, the General Partner will act as Liquidating
Trustee. 
  
 16.4 As soon as possible after December 31, 2035, or
the date of the notice of or event causing an earlier termination of the Partnership, the Liquidating Trustee will begin to wind up the Partnership’s business and affairs. In this regard: 
  
 (a) The Liquidating Trustee will furnish or obtain an
accounting with respect to all Partnership accounts and the account of each Partner and with respect to the Partnership’s assets and liabilities and its operations from the date of the last previous audit of the Partnership to the date of such
dissolution; 
  
 (b) The Liquidating Trustee may,
in its discretion, sell any or all productive and non-productive properties which, except in the case of an election by the General Partner to terminate the Partnership prior to the tenth anniversary of the Effective Date, may be sold to the General
Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner; 
  
 (c) The Liquidating Trustee shall: 
  
 (i) pay all of the Partnership’s debts, liabilities and obligations to its creditors, including the General Partner; and 

 
 (ii) pay all expenses incurred in connection with the
termination, liquidation and dissolution of the Partnership and distribution of its assets as herein provided; 
  
 (d) The Liquidating Trustee shall ascertain the fair market value by appraisal or other reasonable means of all assets of the Partnership
remaining unsold, and each Partner’s capital account shall be charged or credited, as the case may be, as if such property had been sold at such fair market value and the gain or loss realized thereby had been allocated to and among the
Partners in accordance with Article VI hereof; and 
  
 (e) On or as soon as practicable after the effective date of the termination, all remaining cash and any other properties and assets of the Partnership not sold pursuant to the preceding subsections of this Section 16.4 will be distributed
to the Partners (i) in proportion to and to the extent of any remaining balances in the Partners’ capital accounts and then (ii) in undivided interests to the Partners in the same proportions that Partnership Revenues are being shared at the
time of such termination, provided, that: 
  
 (i)
the various interests distributed to the respective Partners will be distributed subject to such liens, encumbrances, restrictions, contracts, operating agreements, obligations, commitments or undertakings as existed with respect to such interests
at the time they were acquired by the Partnership or were subsequently created or entered into by the Partnership; 
  
 (ii) if interests in the Partnership Wells that are not subject to any operating agreement are to be distributed, the Partners will,
concurrently with the distribution, enter into standard form operating agreements covering the subsequent operation of each such well which will, if the termination is effected pursuant to Section 16.1 above, be in a form satisfactory to the General
Partner and will name the General Partner or its designee as operator; and 
  
 (iii) no Partner shall be distributed an interest in any asset if the distribution would result in a deficit balance or increase the deficit balance in its capital account (after making the adjustments referred to in
this Section 16.4 relating to distributions in kind). 
  

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 16.5 If the General Partner has a deficit balance in its capital account following the distribution(s)
provided for in Section 16.4(e) above, as determined after taking into account all adjustments to its capital account for the taxable year of the Partnership during which such distribution occurs, it shall restore the amount of such deficit balance
to the Partnership within ninety (90) days and such amount shall be distributed to the other Partners in accordance with their positive capital account balances. 
  
 16.6 Notwithstanding anything to the contrary in this Agreement, upon the dissolution and termination of the Partnership,
the General Partner will contribute to the Partnership the lesser of: (a) the deficit balance in its capital account; or (b) the excess of 1.01 percent of the total Capital Contributions of the Limited Partners over the capital previously
contributed by the General Partner. 
  
 ARTICLE XVII

 Notices 
  
 17.1 All notices, consents, requests, demands, offers, reports and other communications required or permitted shall be deemed to be given or made when
personally delivered to the party entitled thereto, or when sent by United States mail in a sealed envelope, with postage prepaid, addressed, if to the General Partner, to 7130 South Lewis, Suite 1000, Tulsa, Oklahoma 74136, and, if to a Limited
Partner, to the address set forth below such Limited Partner’s signature on the counterpart of the Subscription Agreement that he or she originally executed and delivered to the General Partner. The General Partner may change its address by
giving notice to all Limited Partners. Limited Partners may change their address by giving notice to the General Partner. 
  
 ARTICLE XVIII 
 Amendments

  
 18.1 Limited Partners do not have the right to propose
amendments to this Agreement. The General Partner may propose an amendment or amendments to this Agreement by mailing to the Limited Partners a notice describing the proposed amendment and a form to be returned by the Limited Partners indicating
whether they oppose or approve of its adoption. Such notice will include the text of the proposed amendment, which will have been approved in advance by counsel for the Partnership. If, within sixty (60) days, or such shorter period as may be
designated by the General Partner, after any notice proposing an amendment or amendments to this Agreement has been mailed, Limited Partners holding a majority of the outstanding Units have properly executed and returned the form indicating that
they approve of and consent to adoption of the proposed amendment, such amendment will become effective as of the date specified in such notice, provided that no amendment which alters the allocations specified in Article VI above, changes the
compensation and reimbursement provisions set forth in Article XI above or is otherwise materially adverse to the interests of the Limited Partners will become effective unless approved by all Limited Partners. If an amendment does become effective,
all Partners will promptly evidence such effectiveness by executing such certificates and other instruments as the General Partner may deem necessary or appropriate under the laws of the jurisdictions in which the Partnership is then doing business
in order to reflect the amendment. 
  
 ARTICLE XIX

 General Provisions 
  
 19.1 This Agreement embodies the entire understanding and agreement between the Partners concerning the Partnership, and supersedes any and all prior
negotiations, understandings or agreements in regard thereto. 
  

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 19.2 In those cases where this Agreement requires opinions to be expressed by, or actions to be approved
by, counsel for Limited Partners, such counsel must be qualified and experienced in the fields of federal income taxation and partnership and securities laws. 
  

19.3 This Agreement and the Subscription Agreement may be executed in multiple counterpart copies, each of which will be considered an original and all
of which constitute one and the same instrument. 
  
 19.4 This
Agreement will be deemed to have been executed and delivered in the State of Oklahoma and will be construed and interpreted according to the laws of that State. 
  

19.5 This Agreement and all of the terms and provisions hereof will be binding upon and will inure to the benefit of the Partners and their respective
heirs, executors, administrators, trustees, successors and assigns. 
  
 EXECUTED in the name of and on behalf of the undersigned General Partner this      day of January, 2005 but effective as of the Effective Date. 
  

									
	 	 	 	 	 	 	“General Partner”
	 	 	 	 	 	 	UNIT PETROLEUM COMPANY
					
	 Attest:
	 	 	 	 	 	 	 	 
					
	 By
	 	  

	 	 	 	 By
	 	  

	 	 	Mark E. Schell, Secretary	 	 	 	 	 	Larry D. Pinkston, President

  

 A-28 

 LIMITED PARTNER SUBSCRIPTION AGREEMENT AND 
 SUITABILITY STATEMENT 
  
 (ALL INFORMATION WILL BE TREATED CONFIDENTIALLY) 
  
 Unit 2005 Employee Oil and Gas Limited Partnership 
 c/o Unit Petroleum Company 
 7130 South Lewis Avenue, Suite 1000 
 Tulsa, Oklahoma 74136 
  

			
	 RE:
	  	Unit 2005 Employee Oil and
	 	  	Gas Limited Partnership

  
 Gentlemen: 
  
 In connection with the subscription of the undersigned for units of limited
partnership interest (“Units”) in the Unit 2005 Employee Oil and Gas Limited Partnership (the “Partnership”) which the undersigned tenders herewith to Unit Petroleum Company (the “General Partner”),
the undersigned is hereby furnishing the Partnership and the General Partner the information set forth herein below and makes the representations and warranties set forth below, to indicate whether the undersigned is a suitable subscriber for Units
in the Partnership. As a condition precedent to investing in the Partnership, the undersigned hereby represents, warrants, covenants and agrees as follows: 
  
 1. The undersigned acknowledges that he or she has received and reviewed a copy of the Private Offering Memorandum (the “Offering
Memorandum”) dated December 23, 2004 of the Unit 2005 Employee Oil and Gas Limited Partnership, relating to the offering of Units in the Partnership, and all Exhibits thereto, including the Agreement of Limited Partnership (the
“Agreement”), and understands that the Units will be offered to others on the terms and in the manner described in the Offering Memorandum. The undersigned hereby subscribes for the number of Units set forth below pursuant to the
terms of the Offering Memorandum and tenders his or her Capital Subscription as required and agrees to pay his or her Additional Assessments upon call or calls by the General Partner; and the undersigned acknowledges that he or she shall have the
right to withdraw this subscription only up until the time the General Partner executes and accepts the undersigned’s subscription and that the General Partner may reject any subscription for any reason without liability to it; and, further,
the undersigned agrees to comply with the terms of the Agreement and to execute any and all further documents necessary in connection with his or her admission to the Partnership. 
  
 2. The undersigned has reviewed and acknowledges execution of the Power of Attorney set forth in the Agreement and elsewhere
in this instrument. 
  
 3. The undersigned is aware that no
federal or state regulatory agency has made any findings or determination as to the fairness for public or private investment, nor any recommendation or endorsement, of the purchase of Units as an investment. 
  

 I-1 

 4. The undersigned recognizes the speculative nature and risks of loss associated with oil and gas
investments and that he or she may suffer a complete loss of his or her investment. The Units subscribed for hereby constitute an investment which is suitable and consistent with his or her investment program and that his or her financial situation
enables him or her to bear the risks of this investment. The undersigned represents that he or she has adequate means of providing for his or her current needs and possible personal contingencies, and that he or she has no need for liquidity of this
investment. 
  
 5. The undersigned confirms that he or she
understands, and has fully considered for purposes of this investment, the RISK FACTORS set forth in the Offering Memorandum and that (i) the Units are speculative investments which involve a high degree of risk of loss by the undersigned of his or
her investment therein, (ii) there is a risk that the anticipated tax benefits under the Agreement could be challenged by the Internal Revenue Service or could be affected by changes in the Internal Revenue Code of 1986, as amended, the regulations
thereunder or administrative or judicial interpretations thereof thereby depriving Limited Partners of anticipated tax benefits, (iii) the General Partner and its affiliates will engage in transactions with the Partnership which may result in a
profit and, in the future, may be engaged in businesses which are competitive with that of the Partnership, and the undersigned agrees and consents to such activities, even though there are conflicts of interest inherent therein, and (iv) there are
substantial restrictions on the transferability of, and there will be no public market for, the Units and, accordingly, it may be difficult for him or her to liquidate his or her investment in the Units in case of emergency, if possible at all.

  
 6. The undersigned confirms that in making his or her decision
to purchase the Units subscribed for he or she has relied upon independent investigations made by him or her (or by his or her own professional tax and other advisors) and that he or she has been given the opportunity to examine all documents and to
ask questions of, and to receive answers from the General Partner or any person(s) acting on its behalf concerning the terms and conditions of the offering or any other matter set forth in the Offering Memorandum, and to obtain any additional
information, to the extent the General Partner possesses such information or can acquire it without unreasonable effort or expense, necessary to verify the accuracy of the information set forth in the Offering Memorandum, and that no representations
have been made to him or her and no offering materials have been furnished to him or her concerning the Units, the Partnership, its business or prospects or other matters, except as set forth in the Offering Memorandum and the other materials
described in the Offering Memorandum. 
  
 7. The undersigned
understands that the Units are being offered and sold under an exemption from registration provided by Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended (the “Act”), and warrants and represents that any Units
subscribed for are being acquired by the undersigned solely for his or her own account, for investment purposes only, and are not being purchased with a view to or for the resale, distribution, subdivision or fractionalization thereof; the
undersigned has no agreement or other arrangement, formal or informal, with any person to sell, transfer or pledge any part of any Units subscribed for or which would guarantee the undersigned any rights to such Units; the undersigned has no plans
to enter into any such agreement or arrangement, and, consequently, he or she must bear the economic 

  

 I-2 

 
risk of the investment for an indefinite period of time because the Units cannot be resold or otherwise transferred unless subsequently registered under the
Act (which neither the General Partner nor the Partnership is obligated to do), or an exemption from such registration is available and, in any event, unless transferred in compliance with the Agreement. 
  
 8. The undersigned further understands that the exemption under Rule 144 of
the Act will not be generally available because of the conditions and limitations of such rule; that, in the absence of the availability of such rule, any disposition by him or her of any portion of his or her investment will require compliance
under the Act; and that the Partnership and the General Partner are under no obligation to take any action in furtherance of making such exemption available. 
  
 9. The undersigned is aware that the General Partner will have full and complete control of Partnership operations and that he or she must depend on the
General Partner to manage the Partnership profitably; and that a Limited Partner does not have the same rights as a stockholder in a corporation or the protection which stockholders might have, since limited partners have limited rights in
determining policy. 
  
 10. The undersigned is aware that the
General Partner will receive compensation for its services irrespective of the economic success of the Partnership. 
  
 11. The undersigned represents and warrants as follows (please mark and complete all applicable categories): 
  
 (a) If an individual, the undersigned is the sole party in
interest, and the undersigned is at least 21 years of age and a bona fide resident and domiciliary (not a temporary or transient resident) of the state set forth opposite his or her signature hereto; 
  
  ̈  YES                     ̈  NO 
  
 (b) If a partnership or corporation, the undersigned meets the following: (1) the entity has not been formed for the purposes of making this investment; (2) the entity was formed on
            ; and (3) the entity has a history of investments similar to the type described in the Offering Memorandum; 
  
  ̈  YES                     ̈  NO 
  
 (c) The undersigned
meets all suitability standards and acknowledges being aware of all legend conditions applicable to his or her state of residence as set forth herein; 
  
  ̈  YES                     ̈  NO 
  

 I-3 

 (d) (i) The undersigned has a net worth (including home, furnishings and automobiles) of
at least five times the amount of his or her Capital Subscription, and anticipates that he or she will have adjusted gross income during the current year in an amount which will enable him or her to bear the economic risks of the investment in the
Partnership; 
  
  ̈  YES                     ̈  NO 
  
 and 
  
 (ii) The undersigned is a salaried employee of Unit Corporation (“UNIT”) or any of its subsidiaries at the date of
formation of the Partnership whose annual base salary for 2004 has been set at $36,000 or more, or the undersigned is a director of UNIT; 
  
  ̈  YES                     ̈  NO 
  
 and

  
 (e) The undersigned
             is or              is not a citizen of the United States. 
  
 12. The undersigned represents and agrees that he or she has had sufficient
opportunity to make inquiries of the General Partner in order to supplement information contained in the Offering Memorandum respecting the offering, and that any information so requested has been made available to his or her satisfaction, and he or
she has had the opportunity to verify such information. The undersigned further agrees and represents that he or she has knowledge and experience in business and financial matters, and with respect to investments generally, and in particular,
investments generally comparable to the offering, so as to enable him or her to utilize such information to evaluate the risks of this investment and to make an informed investment decision. The following is a brief description of the
undersigned’s experience in the evaluation of other investments generally comparable to the offering: 
  
 ________________________________________________________________________________________________________________________________________________ 
  
 ________________________________________________________________________________________________________________________________________________ 
  
 ________________________________________________________________________________________________________________________________________________ 
  
 ________________________________________________________________________________________________________________________________________________ 
  
 13. The undersigned is aware that the Partnership and the General Partner have been and are relying upon the representations and warranties set forth in
this Limited Partner Subscription Agreement and Suitability Statement, in part, in determining whether the offering meets the conditions specified in Rules of the Securities and Exchange Commission and the exemption from registration provided by
Sections 3(b) and/or 4(2) of the Act. 
  

 I-4 

 14. All of the information which the undersigned has furnished the General Partner herein or previously
with respect to the undersigned’s financial position and business experience is correct and complete as of the date of this Agreement, and, if there should be any material change in such information prior to the closing of the offering period
of the Units, the undersigned will immediately furnish such revised or corrected information to the General Partner. The undersigned agrees that the foregoing representations and warranties shall survive his or her admission to the Partnership, as
well as any acceptance or rejection of a subscription for the Units. 
  
 If the subscription tendered hereby of the undersigned is accepted by the General Partner, the undersigned hereby executes and swears to the Agreement of Limited Partnership of Unit 2005 Employee Oil and Gas Limited Partnership as a Limited
Partner, thereby agreeing to all the terms thereof and duly appoints the General Partner, with full power of substitution, his or her true and lawful attorney to execute, file, swear to and record any Certificate of Limited Partnership or amendments
thereto or cancellation thereof and any other instruments which may be required by law in any jurisdiction to permit qualification of the Partnership as a limited partnership or for any other purposes necessary to implement the Partnership’s
purposes. 
  
 THE SECURITIES REPRESENTED BY THIS CERTIFICATE
HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, THE OKLAHOMA SECURITIES ACT OR OTHER APPLICABLE STATE SECURITIES ACTS. THE SECURITIES HAVE BEEN ACQUIRED FOR INVESTMENT AND MAY NOT BE SOLD OR TRANSFERRED FOR VALUE IN THE
ABSENCE OF AN EFFECTIVE REGISTRATION OF THEM UNDER THE SECURITIES ACT OF 1933, AS AMENDED, AND/OR THE OKLAHOMA SECURITIES ACT, OR ANY OTHER APPLICABLE ACT, OR AN OPINION OF COUNSEL TO UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP THAT SUCH
REGISTRATION IS NOT REQUIRED UNDER SUCH ACT. 
  
 The
undersigned hereby subscribes for              Units (minimum subscription: 2 Units) at a price of $1,000 per Unit for a total Capital Subscription (as defined in Article II of the
Agreement) of $                    , which shall be due and payable either: 
  
 (Check One) 
  
  ̈    (a) in four equal installments on March
15, 2005, June 15, 2005, September 15, 2005 and December 15, 2005, respectively; or 
  
  ̈    (b) through equal deductions from 2005 salary of the undersigned commencing immediately after the Effective
Date (as defined in Article II of the Agreement). 
  

 I-5 

							
	LIMITED PARTNER:	    	 RESIDENT
 ADDRESS:
	 	 (If placing Units
 in the name of
spouse
 or trustee for minor
 child or children,
 please provide name,
 address of such
 spouse or trustee and
 Social Security or Tax
 Identification Number)

	  
  

	    	  

	 
	  
  

	    	  

	 
	 Signature
  
  

 Please Print
Name
	    	  
  
 Mailing Address
 if different:
  
  

	 	  
  
 TAX I.D. OR SOCIAL
 SECURITY NO.:
  

	  
 Date:
	 	
	    	  
  

	 	

  
  
 ACCEPTED THIS      DAY OF
                    , 2005. 
  
 UNIT 2005 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP 
  

			
	By	 	  

	 	 	        Authorized Officer of Unit
	 	 	        Petroleum Company, General Partner

  
 Upon completion, an
executed copy of this Limited Partner Subscription Agreement and Suitability Statement should be returned to Unit 2005 Employee Oil and Gas Limited Partnership, Attention Mark E. Schell, 7130 South Lewis Avenue, Suite 1000, Tulsa, Oklahoma 74136.
The General Partner, after acceptance, will return a copy of the accepted Subscription Agreement to the Limited Partner. 
  

 I-6 

 

 
  
 December 23, 2004 
  
 Unit Petroleum Company 
 1000 Kensington Tower I 
 7130 South Lewis 
 Tulsa, Oklahoma 74136 
  
 Re: Unit
2005 Employee Oil and Gas Limited Partnership 
  
 Dear Sirs: 
  
 We have acted as counsel for Unit Petroleum Company, an Oklahoma corporation
(the “General Partner”), which will be the General Partner in the Unit 2005 Employee Oil and Gas Limited Partnership, a proposed Oklahoma limited partnership (the “Partnership”). You have requested our opinions regarding certain
federal income tax matters concerning the Partnership. 
  
 We have
reviewed and relied upon the accuracy of the facts and information set forth in the Private Offering Memorandum dated December 23, 2004 (the “Memorandum”), covering the offer and sale of units of limited partnership interest
(“Units”) in the Partnership, the Agreement of Limited Partnership included as Exhibit A to the Memorandum (the “Partnership Agreement”), the consolidated balance sheet of the General Partner dated October 31, 2004, and such
other documents and matters as we have considered necessary in order to render this opinion. Capitalized terms used herein have the meaning assigned to them in the Memorandum, except as otherwise specifically indicated. 
  
 In our examination we have assumed the authenticity of original documents,
the accuracy of copies and the genuineness of signatures. We have relied upon the representations and statements of the General Partner of the Partnership with respect to the factual determinations underlying the legal conclusions set forth herein.
We have not attempted to verify independently such representations and statements. 
  

 EXHIBIT “B” 

 March 7, 2005 
 Page 2 
  

 Please note that we are opining only as to the matters expressly set forth herein, and no opinion
should be inferred as to any other matters. We are unable to render opinions as to a number of federal income tax issues relating to an investment in Units and the operations of the Partnership. Finally, we are not expressing any opinion with
respect to the amount of allowable losses or credits that may be generated by the Partnership or the amount of each Partner’s share of allowable losses or credits from the Partnership’s activities. 
  
 The following opinion and statements are based upon the provisions of the
Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed regulations thereunder, current administrative rulings, and court decisions. The federal income tax law is uncertain as to many of the tax matters material to an
investment in the Partnership, and it is not possible to predict with certainty how the law will develop or how the courts will decide various issues if they are litigated. While this opinion fairly states our views concerning the tax aspects of an
investment in the Partnership, both the Internal Revenue Service (the “Service”) and the courts may disagree with our position on certain issues. 
  
 Moreover, uncertainty exists concerning some of the federal income tax aspects of the transactions being undertaken by the Partnership. Some of the tax
positions to be taken by the Partnership may be challenged by the Service and there is no assurance that any such challenge will not be successful. Thus, there can be no assurance that all of the anticipated tax benefits of an investment in the
Partnership will be realized. 
  
 Our opinions are based upon the
transactions described in the Memorandum (the “Transaction”) and upon facts as they have been represented to us or determined by us as of the date of the opinion. Any alteration of the facts may adversely affect the opinions rendered. In
our opinion, the preponderance of the material tax benefits, in the aggregate, will be realized by the Partners. It is possible, however, that some of the tax benefits will be eliminated or deferred to future years. 
  
 Because of the factual nature of the inquiry, and in certain cases the lack
of clear authority in the law, it is not possible to reach a judgment as to the outcome on the merits (either favorable or unfavorable) of certain material federal income tax issues as described more fully herein. 
  
 SUMMARY OF CONCLUSIONS 
  
 Opinions expressed: The following is a summary of the specific
opinions expressed by us with respect to the Federal Income Tax Considerations discussed herein. TO BE FULLY UNDERSTOOD, THE COMPLETE DISCUSSION OF THESE MATTERS SHOULD BE READ BY EACH PROSPECTIVE PARTNER. 
  
 1. The material federal income tax benefits in the aggregate from an
investment in the Partnership will be realized. 

 March 7, 2005 
 Page 3 
  

 2. The Partnership will be treated as a partnership for federal income tax purposes and not as a
corporation, an association taxable as a corporation or a “publicly traded partnership.” 
  
 3. To the extent the Partnership’s wells are timely drilled and amounts are timely paid, the Partners will be entitled to their pro rata shares of
the Partnership’s IDC paid in 2005. 
  
 4. Limited
Partners’ interests will be considered a passive activity within the meaning of Code Section 469 and losses generated therefrom will be limited by the passive activity provisions of the Code. 
  
 5. To the extent provided herein, the Partners’ distributive shares of
Partnership tax items will be determined and allocated substantially in accordance with the terms of the Partnership Agreement. 
  
 6. The Partnership will not be required to register with the Service as a tax shelter. 
  
 No opinion expressed: Due to the lack of authority, or the essentially factual nature of the question, we express no
opinion on the following: 
  
 1. The impact of an investment in
the Partnership on an investor’s alternative minimum tax liability, due to the factual nature of the issue. 
  
 2. Whether, under Code Section 183, the losses of the Partnership will be treated as derived from “activities not engaged in for profit,” and
therefore nondeductible from other gross income, due to the inherently factual nature of a Partner’s interest and motive in engaging in the Transaction. 
  
 3. Whether each Partner will be entitled to percentage depletion since such a determination is dependent upon the status of the Partner as an independent
producer. Due to the inherently factual nature of such a determination, we are unable to render an opinion as to the availability of percentage depletion. 
  
 4. Whether any interest incurred by a Partner with respect to any borrowings to acquire a Unit will be deductible or subject to limitations on
deductibility, due to the factual nature of the issue. 
  
 5.
Whether the Partnership will be treated as the tax owner of Partnership Properties acquired by the General Partner as nominee for the Partnership. 
  
 General Information: Certain matters contained herein are not considered to address a material tax consequence and are for general information,
including the matters contained in sections dealing with gain or loss on the sale of Units or of property, Partnership distributions, tax audits, penalties, and state and local tax. 

 March 7, 2005 
 Page 4 
  

 Our opinions are also based upon the facts described in the Memorandum and upon certain
representations made to us by the General Partner for the purpose of permitting us to render our opinions, including the following representations with respect to the Partnership: 
  
 1. The Partnership Agreement to be entered into by and among the General Partner and Limited Partners and any amendments
thereto will be duly executed and will be made available to any Limited Partner upon written request. The Partnership Agreement will be duly recorded in all places required under the Oklahoma Revised Uniform Limited Partnership Act (the
“Act”) for the due formation of the Partnership and for the continuation thereof in accordance with the terms of the Partnership Agreement. The Partnership will at all times be operated in accordance with the terms of the Partnership
Agreement, the Memorandum, and the Act. 
  
 2. No election will be
made by the Partnership, Limited Partners, or the General Partner to be excluded from the application of the provisions of Subchapter K of the Code. 
  
 3. The Partnership will own operating mineral interests, as defined in the Code and in the Regulations, and none of the Partnership’s revenues will
be from non-working interests. 
  
 4. The General Partner will
cause the Partnership to properly elect to deduct currently all Intangible Drilling and Development Costs. 
  
 5. The Partnership will have a December 31 taxable year and will report its income on the accrual basis. 
  
 6. All Partnership wells will be spudded by not later than December 31, 2005.
The entire amount to be paid under any drilling and under the operating agreements entered into by the Partnership will be attributable to Intangible Drilling and Development Costs. 
  
 7. Such drilling and operating agreements will be duly executed and will govern the operation of the Partnership’s
wells. 
  
 8. Based upon the General Partner’s review of its
experience with its previous oil and gas partnerships for the past several years and upon the intended operations of the Partnership, the General Partner believes that the sum of (i) the aggregate deductions, including depletion deductions, and (ii)
350 percent of the aggregate tax credits from the Partnership will not, as of the close of any of the first five years ending after the date on which Units are offered for sale, exceed two times the aggregate cash invested by the Partners in the
Partnership as of such dates. In that regard, the General Partner has reviewed the economics of its similar oil and gas partnerships for the past several years, and has represented that it has determined that none of those partnerships has resulted
in a tax shelter ratio greater than two to one. Further, the General 

 March 7, 2005 
 Page 5 
  

 
Partner has represented that the deductions and credits that are or will be represented as potentially allowable to an investor will not result in the
Partnership having a “tax shelter ratio”, as such term is defined in the Code and regulations thereunder, greater than two to one. 
  
 9. At least 90% of the gross income of the Partnership will constitute income derived from the exploration, development, production, and or marketing of
oil and gas. The General Partner does not believe that any market will ever exist for the sale of Units and the General Partner will not make a market for the Units. Further, the Units will not be traded on an established securities market or the
substantial equivalent thereof. 
  
 10. There is not now pending
nor, to the knowledge of the General Partner or UNIT, threatened any action, suit or proceeding by the Internal Revenue Service under Sections 6700 or 7408 of the Internal Revenue Code relating to the promoter penalty referred to in Section 6700 of
the Code with respect to any partnerships sponsored by the General Partner or UNIT. Neither the General Partner, UNIT, nor, to the knowledge of either of them, any participant in such partnerships has received any pre-filing notifications referred
to in Revenue Procedure 83-73 with respect to such partnerships or the Partnership from the Internal Revenue Service. 
  
 11. The General Partner will, as nominee for the Partnership, acquire and hold title to Partnership Properties on behalf of the Partnership; the General
Partner will enter into an agency agreement before the General Partner acquires any such oil and gas properties on behalf of the Partnership; the agency agreement will reflect that the General Partner’s acquisition of Partnership properties is
on behalf of the Partnership; and the General Partner will execute assignments of all oil and gas interests acquired by it on behalf of the Partnership to the Partnership. 
  
 12. The Partnership and each Partner will have the objective of carrying on the business of the Partnership for profit and
dividing the gain therefrom. 
  
 13. No election will be made
under the Regulations for the Partnership to be treated as a corporation. 
  
 Our opinions are also subject to all the assumptions, qualifications, and limitations set forth in the following discussion, including the assumptions that each of the Partners has full power, authority, and legal
right to enter into and perform the terms of the Partnership Agreement and to take any and all actions thereunder in connection with the transactions contemplated thereby. 
  
 Each prospective investor should be aware that, unlike a ruling from the Service, an opinion of counsel represents only such
counsel’s best judgment. THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT SUCCESSFULLY ASSERT POSITIONS WHICH ARE INCONSISTENT WITH OUR OPINIONS SET FORTH IN THIS DISCUSSION OR IN THE TAX REPORTING POSITIONS TAKEN BY THE  

 March 7, 2005 
 Page 6 
  

 
PARTNERS OR THE PARTNERSHIP. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS OWN TAX ADVISOR TO DETERMINE THE EFFECT OF THE TAX ISSUES DISCUSSED HEREIN ON
HIS INDIVIDUAL TAX SITUATION. 
  
 PARTNERSHIP STATUS

  
 The Partnership will be formed as a limited partnership
pursuant to the Partnership Agreement and the laws of the State of Oklahoma. The characterization of the Partnership as a partnership by state or local law, however, will not be determinative of the status of the Partnership for federal income tax
purposes. The availability of any federal income tax benefits to an investor is dependent upon classification of the Partnership as a partnership rather than as a corporation or as an association taxable as a corporation for federal income tax
purposes. 
  
 We are of the opinion that the Partnership will be
treated as a partnership for federal income tax purposes, and not as a corporation, an association taxable as a corporation or a “publicly traded partnership.” However, there can be no assurance that the Service will not attempt to treat
the Partnership as a corporation or as an association taxable as a corporation for federal income tax purposes. If the Service were to prevail on this issue, the tax benefits associated with taxation as a partnership would not be available to the
Partners. 
  
 Although the Partnership will be validly organized
as a limited partnership under the laws of the state of Oklahoma and will be subject to the Act, whether it will be treated for federal income tax purposes as a partnership or as a corporation or as an association taxable as a corporation will be
determined under the Code rather than local law. As discussed below, our opinion that the Partnership will not be classified a corporation or as an association taxable as a corporation is based in part on entity classification regulations
promulgated in 1996 and in part on the fact that in our opinion the Partnership will not constitute a “publicly traded partnership.” 
  
 A. Association Taxable as a Corporation 
  
 Our opinion that the Partnership will not be treated as an association taxable as a corporation is based on regulations issued by the Internal Revenue
Service on December 17, 1996, generally effective as of January 1, 1997, regarding the tax classification of certain business organizations (the “Check the Box Regulations”). 
  
 Under the Check the Box Regulations, in general, a business entity that is not otherwise required to be treated as a
corporation under such regulations will be classified as a partnership if it has two or more members, unless the business entity elects to be treated as a corporation. The Partnership is not required under the Check the Box Regulations to be treated
as a corporation and the General Partner has represented that it will not elect that the Partnership be treated as a corporation. Accordingly, in our opinion the Partnership will not be treated as an association taxable as a corporation. 

 March 7, 2005 
 Page 7 
  

 B. Publicly Traded Partnerships 
  
 The Revenue Act of 1987 (the “1987 Act”) added Code Section 7704, “Certain Publicly Traded Partnerships
Treated as Corporations.” In treating certain “publicly traded partnerships” (“PTPs”) as corporations for federal income tax purposes, Congress defined a PTP as any partnership, interests in which are either traded on an
established securities market or readily tradable on a secondary market (or the substantial equivalent thereof). Code Section 7704(b). Proposed Regulation 1.7704-1(b) provides that an “established securities market” includes a national
securities exchange registered under Section 6 of the Securities Exchange Act of 1934 (the “1934 Act”), a national securities exchange exempt under the 1934 Act because of the limited volume of transactions, certain foreign security laws,
regional or local exchanges, and an interdealer quotation system that regularly disseminates firm buy or sell quotations by identified brokers or dealers. The General Partner has represented that the Units will not be traded on an established
securities market. 
  
 Notwithstanding the above general treatment
of PTPs, Code Section 7704(c) creates an exception to the treatment of PTPs as corporations for any taxable year if 90% or more of the gross income of the partnership for such taxable year consists of “qualifying income.” Code Section
7704(c)(2). For this purpose, qualifying income is defined to include, inter alia, “income and gains derived from the exploration, development, mining or production, processing, refining... or the marketing of any mineral or natural
resource...” Code Section 7704(d)(1)(E). The General Partner has represented that for all taxable years of the Partnership, 90% or more of the Partnership’s gross income will consist of such qualifying income. 
  
 Regarding the definition of PTPs contained in the Code, the Committee Reports
to the 1987 Act provide that PTPs include entities with respect to which, inter alia, (i) ”the holder of an interest has a readily available, regular and ongoing opportunity to sell or exchange his interest through a public means of
obtaining or providing information of offers to buy, sell or exchange interests,” (ii) ”prospective buyers and sellers have the opportunity to buy, sell or exchange interests in a time frame and with the regularity and continuity that the
existence of a market maker would provide,” and (iii) there exists a “regular plan of redemptions or repurchases” or similar acquisitions of interests in the partnership such that holders of interests have readily available, regular
and ongoing opportunities to dispose of their interests.” 
  
 The Service issued Regulation Section 1.7704-1 to clarify when partnership interests that are not traded on an established securities market will be treated as readily tradable on a secondary market or the substantial equivalent thereof.
Essentially, the Regulation provides that such a situation occurs if partners are readily able to buy, sell, or exchange their partnership interests in a manner that is comparable, economically, to trading on an established securities market. In
addition, Notice 88-76 and the Regulation provide limited safe harbors from the definition of a PTP in advance of the issuance of final regulations. It is unclear whether the limited safe harbors provided in the Notice and Regulation would result in
the Units being treated as not publicly traded and we express no opinion regarding this matter. However, the General Partner’s obligation to purchase Units pursuant to the right or presentment described in 

 March 7, 2005 
 Page 8 
  

 
the Memorandum is conditioned upon the receipt by the Partnership from its counsel of an opinion that such offers or obligations to offer will not cause the
Partnership to be treated as “publicly traded.” 
  
 Due
to the presence of the opinion of counsel condition, the Partnership, in our opinion, will not be treated as a PTP prior to any purchases of Units pursuant to the right of presentment. Accordingly, the Partnership, in our opinion, will not be
treated as a corporation for federal income tax purposes under Code Section 7704 in the absence of the Partnership’s interests being “readily tradable on a secondary market (or the substantial equivalent thereof).” 
  
 Notwithstanding the above, the Service may promulgate regulations or release
announcements which take the position that interests in partnerships such as the Partnership are readily tradable on a secondary market or the substantial equivalent thereof. However, treatment of the Partnership as a PTP should not result in its
treatment as a corporation for federal income tax purposes due to the exception contained in Code Section 7704(c) relating to PTPs meeting the 90% of gross income test so long as such gross income test is satisfied. 
  
 C. Summary 
  
 Based on the above, in our opinion the Partnership will not be treated as an association taxable as corporation for federal
income tax purposes by reason of the Check the Box Regulations. Further, since any obligation of the General Partner to purchase Units is conditioned upon the receipt of an opinion of counsel that the Partnership will not be treated as a PTP, and
assuming the Partnership satisfies the 90% gross income test of Code Section 7704, the Partnership, in our opinion, will not be treated as a corporation for federal income tax purposes. Accordingly, the Partnership in our opinion will be treated as
partnership for federal income tax purposes. If challenged by the Service on this issue, the Partners should prevail on the merits, and each Partner should be required to report his proportionate share of the Partnership’s items of income and
deductions on his individual federal income tax return. 
  
 If in
any taxable year the Partnership were to be treated for federal income tax purposes as a corporation or as an association taxable as a corporation, the Partnership income, gain, loss, deductions, and credits would be reflected only on its
“corporate” tax return rather than being passed though to the Partners. In such event, the Partnership would be required to pay income tax at corporate rates on its net income, thereby reducing the amount of cash available to be
distributed to the Partners. Additionally, all or a portion of any distribution made to Partners would be taxable as dividends, which would not be deductible by the Partnership and which would generally be treated as ordinary portfolio income to the
Partners, regardless of the source from which such distributions were generated. 
  
 The discussion that follows is based on the assumption that the Partnership will be classified as a partnership for federal income tax purposes. 

 March 7, 2005 
 Page 9 
  

 FEDERAL TAXATION OF THE PARTNERSHIP 
  
 Under the Code, a partnership is not a taxable entity and, accordingly,
incurs no federal income tax liability. Rather, a partnership is a “pass-through” entity which is required to file an information return with the Service. In general the character of a partner’s share of each item of income, gain,
loss, deduction, and credit is determined at the partnership level. Each partner is allocated a distributive share of such items in accordance with the partnership agreement and is required to take such items into account in determining the
partner’s income. Each partner includes such amounts in income for any taxable year of the partnership ending within or with the taxable year of the partner, without regard to whether the partner has received or will receive any cash
distributions from the Partnership. 
  
 A partnership anti-abuse
regulation promulgated under Reg. Section 1.701-2 authorizes the Service to recharacterize a partnership transaction if (1) a partnership is formed or availed of in connection with a transaction a principal purpose of which is to reduce
substantially the present value of the partners’ aggregate federal income tax liability, and (2) the transaction is inconsistent with the intent of the Subchapter K partnership provisions. Additionally, the regulation permits the Service
to treat a partnership as an aggregate of its partners, in whole or in part, as appropriate, to carry out the purpose of any provision of the Code or the regulations. The scope of this regulation is unclear at this time. Accordingly, we are unable
to express an opinion as to its effect, if any, on the Partnership. 
  
 REGISTRATION AS A TAX SHELTER 
  
 The Code
provides that certain investments must be registered as tax shelters with the Service. Registration numbers for such tax shelters must be supplied to investors who are required to report the numbers on their personal tax returns. Any organizer of a
“potentially abusive tax shelter” and any person selling an interest in such shelter are required to maintain a list of investors in such tax shelter to whom interests were sold (together with other identifying information) and to make the
list available to the Service upon request. Any tax shelter which is required to be registered and any other plan or arrangement which is of a type determined by the Treasury Regulations as having a potential for tax avoidance or evasion is
considered a potentially abusive tax shelter for this purpose. 
  
 The registration requirements apply only to an investment with respect to which any person could reasonably infer from the representations made, or to be made, in connection with the offering for sale of interests in the investment that the
“tax shelter ratio” for any investor is greater than two to one as of the close of any of the first five years ending after the date on which such investment is offered for sale. 
  
 The General Partner has represented that, (i) based upon its experience with
its oil and gas partnerships and upon the intended operations of the Partnership, it does not believe that the Partnership will have a tax shelter ratio greater than two to one, (ii) the deductions and credits that are or will be represented as
potentially allowable to an investor will not result in any 

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Partnership having a tax shelter ratio greater than two to one, and (iii) based upon a review of the economics of its similar oil and gas partnerships for
the past several years, it has determined that none of those partnerships has resulted in a tax shelter ratio greater than two to one. Accordingly, the General Partner does not intend to cause the Partnership to register with the Service as a tax
shelter. Based on the foregoing representations, we are of the opinion that the Partnership will not be required to register with the Service as a tax shelter. 
  

If it is subsequently determined that the Partnership was required to be registered with the Service as a tax shelter, the Partnership would be subject
to certain penalties under Code Section 6707, including a penalty ranging from $500 to 1% of the aggregate amount invested in Units for failing to register and $100 for each failure to furnish to a Partner a tax shelter registration number, and each
Partner would be liable for a $250 penalty for failure to include the tax registration number on his tax return, unless such failure was due to reasonable cause. A Partner also would be liable for a penalty of $100 for failing to furnish the tax
shelter registration number to any transferee of his Partnership interest. We can give no assurance that, if the Partnership is determined to be a tax shelter which must be registered with the Service, the above penalties will not apply. 

 
 OWNERSHIP OF PARTNERSHIP PROPERTIES 
  
 The General Partner has indicated that it, as nominee for the Partnership
(the “Nominee”), will acquire and hold title to Partnership Properties on behalf of the Partnership. The Nominee and the Partnership will enter into an agency agreement before the Nominee acquires any oil and gas properties on behalf of
the Partnership. That agency agreement will reflect that the Nominee’s acquisition of Partnership Properties is on behalf of the Partnership. For various cost and procedural reasons, the assignments of all oil and gas interests acquired by the
Nominee on behalf of the Partnership to the Partnership will not be recorded in the real estate records in the counties in which the Partnership Properties are located. That is, while the Partnership will be the owner of the Partnership Properties,
there will be no public record of that ownership. It is possible that the Service could assert that the Nominee should be treated for federal income tax purposes as the owner of the Partnership Properties, notwithstanding the assignment of those
Partnership Properties to the Partnership. If the Service were to argue successfully that the Nominee should be treated as the tax owner of the Partnership Properties, there would be significant adverse federal income tax consequences to the Limited
Partners, such as the unavailability of depletion deductions in respect of income from Partnership Properties. The Service is concerned that taxpayers not be able to shift the tax consequences of transactions between parties based on the
parties’ declaration that one party is the agent of another; the Service generally requires that taxpayers respect the form of their transactions and ownership of property. Based on this concern, the Service may challenge the Partnership’s
treatment of Partnership Properties, and tax attributes thereof, which are held of record by the Nominee. 
  
 In Commissioner of Internal Revenue v. Bollinger, 485 U.S. 340 (1988), the United States Supreme Court reviewed a principal-agent relationship and
held for the taxpayer in concluding that the principal should be treated as the tax owner of property held in the name of the agent. In 

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that case the Supreme Court noted that “It seems to us that the genuineness of the agency relationship is adequately assured, and tax-avoiding
manipulation adequately avoided, when the fact that the corporation is acting as agent for its shareholders with respect to a particular asset is set forth in a written agreement at the time the asset is acquired, the corporation functions as agent
and not principal with respect to the asset for all purposes, and the corporation is held out as the agent and not principal in all dealings with third parties relating to the asset.” While the Partnership and the Nominee will have in place an
agreement defining their relationship before any Partnership Properties are acquired by the Nominee and the Nominee will function as agent with respect to those Partnership Properties on behalf of the Partnership, the Nominee will not hold itself
out to all third parties as the agent of the Partnership in dealings relating to the Partnership Properties. Unlike the relationship between the principal and the agent in Bollinger, the Nominee will, however, assign title to Partnership
Properties to the Partnership, but will not record those assignments. Accordingly, the facts related to the relationship between the Nominee and the Partnership are not the same as the facts in Bollinger and it is not clear that the failure
of the Nominee to hold itself out to third parties as the agent of the Partnership in dealings relating to Partnership Properties would result in the treatment of the Nominee as the tax owner of the Partnership Properties. For the foregoing reasons,
we have not expressed an opinion on this issue, but we believe that substantial arguments may be made that the Partnership should be treated as the tax owner of Partnership Properties acquired by the Nominee on the Partnership’s behalf. If the
Partnership were not treated as the tax owner of the Partnership Properties, then our conclusions with respect to the following discussions which relate to the Partners’ deduction of tax items which are derived from Partnership Properties, such
as IDC, depletion and Depreciation, would not be applicable. 
  
 INTANGIBLE DRILLING AND DEVELOPMENT COSTS DEDUCTIONS 
  
 Under Code Section 263(a), taxpayers are denied deductions for capital expenditures, which expenditures are those that generally result in the creation of an asset having a useful life which extends substantially beyond the close of the
taxable year. See also Treas. Reg. Section 1.461-1(a)(2). In Indopco, Inc. v. Commissioner, 92-1 USTC paragraph 50,113 (1992), the Supreme Court seemed to further limit the capitalization criteria by stating that the costs should be
capitalized when they provide benefits that extend beyond one tax year. Notwithstanding these statutory and judicial general rules, Congress has granted to the Secretary of the Treasury the authority to prescribe regulations that would allow
taxpayers the option of deducting, rather than capitalizing, intangible drilling and development costs (“IDC”). Code Section 263. The Secretary’s rules are embodied in Treas. Reg. Section 1.612-4 and state that, in general, the option
to deduct IDC applies only to expenditures for drilling and development items that do not have a salvage value. 
  
 With respect to IDC incurred by a partnership, Code Section 703 and Treas. Reg. Section 1.703-1(b) provide that the option to deduct such costs is to be
exercised at the partnership level and in the year in which the deduction is to be taken. All partners are bound by the partnership’s election. The General Partner has represented that the Partnership will elect to deduct IDC in accordance with
Treas. Reg. Section 1.612-4. In this regard, subject to such 

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provision, Limited Partners will be entitled to deduct IDC against passive income in the year in which the investment is made, provided wells are spudded
within the first ninety days of the following year. 
  
 A. Classification of
Costs 
  
 In general, IDC consists of those costs which in
and of themselves have no salvage value. Treas. Reg. Section 1.612-4(a) provides examples of items to which the option to deduct IDC applies, including all amounts paid for labor, fuel, repairs, hauling, and supplies, or any of them, which are used
(i) in the drilling, shooting, and cleaning of wells, (ii) in such clearing of ground, draining, road making, surveying, and geological works as are necessary in the preparation for the drilling of wells, and (iii) in the construction of such
derricks, tanks, pipelines, and other physical structures as are necessary for the drilling of wells and the preparation of wells for the production of oil or gas. The Service, in Rev. Rul. 70-414, 1970-2 C.B. 132, set forth further classifications
of items subject to the option and those considered capital in nature. The ruling provides that the following items are not subject to the election of Treas. Reg. Section 1.612-4(a): (i) oil well pumps (upon initial completion of the well),
including the necessary housing structures; (ii) oil well pumps (after the well has flowed for a time), including the necessary housing structures; (iii) oil well separators, including the necessary housing structures; (iv) pipelines from the
wellhead to oil storage tanks on the producing lease; (v) oil storage tanks on the producing lease; (vi) salt water disposal equipment, including any necessary pipelines; (vii) pipelines from the mouth of a gas well to the first point of control,
such as a common carrier pipeline, natural gasoline plant, or carbon black plant; (viii) recycling equipment, including any necessary pipelines; and (ix) pipelines from oil storage tanks on the producing leasehold to a common carrier pipeline.

  
 A partnership’s classification of a cost as IDC is not
binding on the government, which might reclassify an item labeled as IDC as a cost which must be capitalized. In Bernuth v. Commissioner, 57 T.C. 225 (1971), aff’d, 470 F.2d 710 (2nd Cir. 1972), the Tax Court denied taxpayers a
deduction for that portion of a turnkey drilling contract price that was in excess of a reasonable cost for drilling the wells in question under a turnkey contract, holding that the amount specified in the turnkey contract was not controlling.
Similarly, the Service, in Rev. Rul. 73-211, 1973-1 C.B. 303, concluded that excessive turnkey costs are not deductible as IDC: 
  
 [o]nly that portion of the amount of the taxpayer’s total investment that is attributable to intangible drilling and development costs that would
have been incurred in an arm’s-length transaction with an unrelated drilling contractor (in accordance with the economic realities of the transaction) is deductible [as IDC]. 
  
 To the extent the Partnership’s prices meet the reasonable price standards imposed by Bernuth, supra, and
Rev. Rul 73-211, supra, and to the extent such amounts are not allocable to tangible property, leasehold costs, and the like, the amounts paid to the General Partner or its affiliates under drilling contracts should qualify as IDC and should
be deductible at the time described below under “B. Timing of Deductions.” That portion of the amount paid to the 

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General Partner or its affiliates that is in excess of the amount that would be charged by an independent driller under similar conditions will not qualify
as IDC and will be required to be capitalized. 
  
 We are unable
to express an opinion regarding the reasonableness or proper characterization of the payments under the drilling contracts, since the determination of whether the amounts are reasonable or excessive is inherently factual in nature. No assurance can
be given that the Service will not characterize a portion of the amount paid to the General Partner or its affiliates as an excessive payment, to be capitalized as a leasehold cost, assignment fee, syndication fee, organization fee, or other cost,
and not deductible as IDC. To the extent not deductible such amounts will be included in the Partners’ bases in their interests in the Partnership. 
  
 B. Timing of Deductions 
  
 As described above, Code Section 263(c) and Treas. Reg. Section 1.612-4 allow the Partnership to expense IDC as opposed to capitalizing such amounts. Even
if the Partnership elects to expense the IDC, assuming a taxpayer is otherwise entitled to such a deduction, the taxpayer may elect to capitalize all or a part of the IDC and amortize the same on a straight-line basis over a sixty month period,
beginning with the taxable month in which such expenditure is made. Code Section 59(e)(1) and (2)(c). 
  
 For taxpayers entitled to deduct IDC, the timing of such deduction can vary, depending, in part, upon the taxpayer’s method of accounting. The
General Partner has represented that the Partnership will use the accrual method of accounting. Under the accrual method, income is recognized when all the events have occurred which fix the right to receive such income and the amount thereof can be
determined with reasonable accuracy. Treas. Reg. Section 1.451-1(a). With respect to deductions, recognition results when all events which establish liability have occurred and the amount thereof can be determined with reasonable accuracy. Treas.
Reg. Section 1.461-1(a)(2). Regarding deductions, Code Section 461(h)(1) provides that “. . . the all events test shall not be treated as met any earlier than when economic performance with respect to such item occurs.” 
  
 Code Section 461(i)(2), provides that, in the case of a “tax
shelter,” economic performance with respect to the act of drilling an oil or gas well will “. . . be treated as having occurred within a taxable year if drilling of the well commences before the close of the 90th day after the close of the
taxable year.” The Code Section 461 definition of a “tax shelter” is expansive and would include the Partnership. However, with respect to a tax shelter which is a partnership, the maximum deduction that would be allowable for any
prepaid expenses under this exception would be limited to the partner’s “cash basis” in the partnership. Code Section 461(i)(2)(B)(i). Such “cash basis equals the partner’s adjusted basis in the partnership, determined
without regard to (i) any liability of the partnership and (ii) any amount borrowed by the partner with respect to the partnership which (I) was arranged by the partnership or by any person who participated in the organization, sale, or management
of the partnership (or any 

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person related to such person within the meaning of Code Section 465(b)(3)(C)) or (II) was secured by any assets of the partnership”. Code Section
461(i)(2)(C). The General Partner has represented that drilling operations for Partnership wells will commence by the spudding of each well on or before December 31, 2005. If completion is warranted, each well will be completed with due diligence
thereafter. Further the General Partner has represented that, in any event, the Partnership will not have any such liability referred to in Code Section 461(i)(2)(C), and the Partners will not so incur any such debt so as to result in application of
the limiting provisions contained in Code Section 461(i)(2)(B)(i). 
  
 Notwithstanding the above, the deductibility of any prepaid IDC will be subject to the limitations of case law. These limitations provide that prepaid IDC is deductible when paid if (i) the expenditure constitutes a payment that is not
merely a deposit, (ii) the payment is made for a business purpose, and (iii) deductions attributable to such outlay do not result in a material distortion of income. See Keller v. Commissioner, 79 T.C. 7 (1982), aff’d, 725 F.2d
1173 (8th Cir. 1984), Rev. Rul. 71-252, 1971-1 C.B. 146, Pauley v. U.S., 63-1 U.S.T.C. paragraph 9280 (S.D. Cal. 1963), Rev. Rul. 80-71, 1980-1 C.B. 106, Jolley v. Commissioner, 47 T.C.M. 1082 (1984), Dillingham v. U.S., 81-2
U.S.T.C. paragraph 9601 (W.D. Okla. 1981), and Stradlings Building Materials, Inc. v. Commissioner, 76 T.C. 84 (1981). Generally, these requirements may be met by a showing of a legally binding obligation (i.e., the payment was not merely a
deposit), of a legitimate business purpose for the payment, that performance of the services was required within a reasonable time, and of an arm’s-length price. Similar requirements apply to cash basis taxpayers seeking to deduct prepaid IDC.

  
 The General Partner is unable to represent that all of the
Partnership’s wells will be completed in 2005; however, the General Partner has represented that any such well that is not completed in 2005 will be spudded by not later than December 31, 2005. 
  
 The Service has challenged the timing of the deduction of IDC when the wells
giving rise to such deduction have been completed in a year subsequent to the year of prepayment. The decisions noted above hold that prepayments of IDC by a cash basis taxpayer are, under certain circumstances, deductible in the year of prepayment
if some work is performed in the year of prepayment even though the well is not completed that year. 
  
 In Keller v. Commissioner, supra, the Eighth Circuit Court of Appeals applied a three-part test for determining the current deductibility of
prepaid IDC by a cash basis taxpayer, namely whether (i) the expenditure was a payment or a mere deposit, (ii) the payment was made for a valid business purpose and (iii) the prepayment resulted in a material distortion of income. The facts in that
case dealt with two different forms of drilling contracts: footage or day-work contracts and turnkey contracts. Under the turnkey contracts, the prepayments were not refundable in any event, but in the event work was stopped on one well the
remaining unused amount would be applied to another well to be drilled on a turnkey basis. Contrary to the Service’s argument that this substitution feature rendered the payment a mere deposit, the court in Keller concluded that the
prepayments were indeed “payments” because the taxpayer could not compel a refund. The court further found that the deduction clearly reflected income because 

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under the unique characteristics of the turnkey contract the taxpayer locked in the price and shifted the drilling risk to the contractor, for a premium,
effectively getting its bargained for benefit in the year of payment. Therefore, the court concluded that the cash basis taxpayers in that case properly could deduct turnkey payments in the year of payment. With respect to the prepayments under the
footage or day-work contracts, however, the court found that the payments were mere deposits on the facts of the case, because the partnership had the power to compel a refund. The court was also unconvinced as to the business purpose for prepayment
under the footage or day-work contracts, primarily because the testimony indicated that the drillers would have provided the required services with or without prepayment. 
  
 Under the terms of drilling and operating agreements to be entered into by and between the Partnership and the General
Partners or its affiliates, if amounts paid by the Partnership prior to the commencement of drilling exceed amounts due the General Partner or its affiliates thereunder, the General Partner or its affiliates will not refund any portion of amounts
paid by the Partnership, but rather will create a credit once the actual costs incurred by the General Partner or its affiliates are compared to the amounts paid. 
  
 The Service has adopted the position that the relationship between the parties may provide evidence that the drilling
contract between the parties requiring prepayment may not be a bona fide arm’s-length transaction, in which case a portion of the prepayment may be disallowed as being a “non-required payment.” Section 4236, Internal Revenue Service
Examination Tax Shelters Handbook (6-27-85). A similar position is taken by the Service in the Tax Shelter Audit Technique Guidelines. Internal Revenue Service Examination Tax Shelter Handbook. 
  
 The Service has formally applied its position on prepayments to related
parties in Revenue Ruling 80-71. 1980-1 C.B. 106. In this ruling, a subsidiary corporation, which was a general partner in an oil and gas limited partnership, prepaid the partnership’s drilling and completion costs under a turnkey contract
entered into with the corporate parent of the general partner. The agreement did not provide for any date for commencing drilling operations and the contractor, which did not own any drilling equipment, was to arrange for the drilling equipment for
the wells through subcontractors. Revenue Ruling 71-252, supra, was factually distinguished on the grounds of the business purpose of the transaction, immediate expenditure of prepaid receipts, and completion of the wells within two and
one-half months. Rev. Rul. 80-71 found that the prepayment was not made in accordance with customary business practice and held on the facts that the payment was deductible in the tax year that the related general contractor paid the independent
subcontractor. 
  
 However, in Tom B. Dillingham v. United
States, 1981-2 USTC paragraph 9601 (D.C. Okla. 1981), the court held that, on the facts before it, a contract between related parties requiring a prepaid IDC did give rise to a deduction in the year paid. In that case, Basin Petroleum Corp.
(“Basin”) was the general partner of several drilling partnerships and also served as the partnership operator and general contractor. As general contractor, Basin was to conduct the drilling of the wells at a fixed price on a turnkey
basis under an agreement that required payment prior to the end of the year in question. The stated reason for the prepayment 

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was to provide Basin with working capital for the drilling of the wells and to temporarily provide funds to Basin for other operations. The agreement
required drilling to commence within a reasonable period of time, and all wells were completed within the following year. Some of the wells were drilled by Basin with its own rigs and some were drilled by subcontractors. The court stated:

  
 The fact that the owner and contractor is the general partner
of the partnership-owner does not change this result where, as here, the Plaintiffs have shown that prepayment was required for a legitimate business purpose and the transaction was not a sham to merely permit Plaintiff to control the timing of the
deduction. IRC, Sec. 707(a). Plaintiffs were entitled to rely upon Revenue Ruling 71-252 by reason of Income Tax Regulations 26 C.F.R. Section 601.601(d)(2)(v)(e) . . . 
  
 Notwithstanding the foregoing, no assurance can be given that the Service will not challenge the current deduction of IDC because of the
prepayment being made to a related party. If the Service were successful with such challenge, the Partners’ deductions for IDC would be deferred to later years. 
  
 The timing of the deductibility of prepaid IDC is inherently a factual determination which is to a large extent predicated
on future events. The General Partner has represented that the drilling and operating agreements to be entered into with an affiliate of the General Partner by the Partnership will be duly executed by and delivered to such affiliate, the Partnership
and the General Partner as attorney-in-fact for the Partners and will govern the drilling, and, if warranted, the completion of each of the Partnership=s wells. Based upon this representation and others included within the opinion and assuming that
the drilling and operating agreements will be performed in accordance with their terms, we are of the opinion that the payment for IDC under the drilling and operating agreements, if made in 2005, will be allowable as a deduction in 2005, subject to
the other limitations discussed in this opinion. Although the General Partner will attempt to satisfy each requirement of the Service and judicial authority for deductibility of IDC in 2005, no assurance can be given that the Service will not
successfully contend that the IDC of a well which is not completed until 2006 are not deductible in whole or in part until 2006 

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 C. Recapture of IDC 
  

IDC which has been deducted is subject to recapture as ordinary income upon certain dispositions (other than by abandonment, gift, death, or tax-free
exchange) of an interest in an oil or gas property. IDC previously deducted that is allocable to the property (directly or through the ownership of an interest in a partnership) and which would have been included in the adjusted basis of the
property is recaptured to the extent of any gain realized upon the disposition of the property. Treasury Regulations provide that recapture is determined at the partner level (subject to certain anti-abuse provisions). Treas. Reg. Section
1.1254-5(b). Where only a portion of recapture property is disposed of, any IDC related to the entire property is recaptured to the extent of the gain realized on the portion of the property sold. In the case of the disposition of an undivided
interest in a property (as opposed to the disposition of a portion of the property), a proportionate part of the IDC with respect to the property is treated as allocable to the transferred undivided interest to the extent of any realized gain.
Treas. Reg. Section 1.1254-1(c). 
  
 DEPLETION DEDUCTIONS

  
 The owner of an economic interest in an oil and gas
property is entitled to claim the greater of percentage depletion or cost depletion with respect to oil and gas properties which qualify for such depletion methods. In the case of partnerships, the depletion allowance must be computed separately by
each partner and not by the partnership. Code Section 613A(c)(7)(D). Notwithstanding this requirement, however, the Partnership, pursuant to Section 3.01(d)(i) of the Partnership Agreement, will compute a “simulated depletion allowance” at
the Partnership level, solely for the purposes of maintaining Capital Accounts. Code Sections 613A(d)(2) and 613A(d)(4). 
  
 Cost depletion for any year is determined by multiplying the number of units (e.g., barrels of oil or Mcf of gas) sold during the year by a
fraction, the numerator of which is the cost of the mineral interest and the denominator of which is the estimated recoverable units of reserve available as of the beginning of the depletion period. See Treas. Reg. Section 1.611-2(a). In no event
can the cost depletion exceed the adjusted basis of the property to which it relates. 
  
 Percentage depletion is generally available only with respect to the domestic oil and gas production of certain “independent producers.” In order to qualify as an independent producer, the taxpayer, either
directly or through certain related parties, may not be involved in the refining of more 50,000 barrels of oil (or equivalent of gas) on any day during the taxable year or in the retail marketing of oil and gas products exceeding $5 million per year
in the aggregate. 
  
 In general, (i) component members of a
controlled group of corporations, (ii) corporations, trusts, or estates under common control by the same or related persons and (iii) members of the same family (an individual, his spouse and minor children) are aggregated and treated as one
taxpayer in determining the quantity of production (barrels of oil or cubic feet of gas per day) qualifying for percentage depletion under the independent producer’s exemption. 

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Code Section 613A(c)(8). No aggregation is required among partners or between a partner and a partnership. An individual taxpayer is related to an entity
engaged in refining or retail marketing if he owns 5% or more of such entity. Code Section 613A(d)(3). 
  
 Percentage depletion is a statutory allowance pursuant to which, under current law, a minimum deduction equal to 15% of the taxpayer’s gross income
from the property is allowed in any taxable year, not to exceed (i) 100% of the taxpayer’s taxable income from the property (computed without the allowance for depletion) or (ii) 65% of the taxpayer’s taxable income for the year (computed
without regard to percentage depletion and net operating loss and capital loss carrybacks). Code Sections 613(a) and 613A(d)(1). The rate of the percentage depletion deduction will vary with the price of oil. In the case of production from marginal
properties, the percentage depletion rate may be increased. Section 613A(c)(6). For purposes of computing the percentage depletion deduction, “gross income from the property” does not include any lease bonus, advance royalty, or other
amount payable without regard to production from the property. Code Section 613A(d)(5). Depletion deductions reduce the taxpayer’s adjusted basis in the property. However, unlike cost depletion, deductions under percentage depletion are not
limited to the adjusted basis of the property; the percentage depletion amount continues to be allowable as a deduction after the adjusted basis has been reduced to zero. 
  
 Percentage depletion will be available, if at all, only to the extent that a taxpayer’s average daily production of
domestic crude oil or domestic natural gas does not exceed the taxpayer’s depletable oil quantity or depletable natural gas quantity, respectively. Generally, the taxpayer’s depletable oil quantity equals 1,000 barrels and depletable
natural gas quantity equals 6,000,000 cubic feet. Code Section 613A(c)(3) and (4). In computing his individual limitation, a Partner will be required to aggregate his share of the Partnership’s oil and gas production with his share of
production from all other oil and gas investments. Code Section 613A(c). Taxpayers who have both oil and gas production may allocate the deduction limitation between the two types of production. 
  
 The availability of depletion, whether cost or percentage, will be determined
separately by each Partner. Each Partner must separately keep records of his share of the adjusted basis in an oil or gas property, adjust such share of the adjusted basis for any depletion taken on such property, and use such adjusted basis each
year in the computation of his cost depletion or in the computation of his gain or loss on the disposition of such property. These requirements may place an administrative burden on a Partner. For properties placed in service after 1986, depletion
deductions, to the extent they reduce the basis of an oil and gas property, are subject to recapture under Section 1254. 
  
 SINCE THE AVAILABILITY OF PERCENTAGE DEPLETION FOR A PARTNER IS DEPENDENT UPON THE STATUS OF THE PARTNER AS AN INDEPENDENT PRODUCER, WE ARE UNABLE TO
RENDER ANY OPINION AS TO THE AVAILABILITY OF PERCENTAGE DEPLETION. EACH PROSPECTIVE INVESTOR IS URGED TO CONSULT WITH HIS PERSONAL TAX ADVISOR TO DETERMINE WHETHER PERCENTAGE DEPLETION WOULD BE AVAILABLE TO HIM. 

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 DEPRECIATION DEDUCTIONS 
  
 The Partnership will claim depreciation, cost recovery, and amortization deductions with respect to its basis in Partnership
Property as permitted by the Code. For most tangible personal property placed in service after December 31, 1986, the “modified accelerated cost recovery system” (“MACRS”) must be used in calculating the cost recovery deductions.
Thus, the cost of lease equipment and well equipment, such as casing, tubing, tanks, and pumping units, and the cost of oil or gas pipelines cannot be deducted currently but must be capitalized and recovered under “MACRS.” The cost
recovery deduction for most equipment used in domestic oil and gas exploration and production and for most of the tangible personal property used in natural gas gathering systems is calculated using the 200% declining balance method switching to the
straight-line method, a seven-year recovery period, and a half-year convention. 
  
 INTEREST DEDUCTIONS 
  
 In
the Transaction, the Limited Partners will acquire their interests by remitting cash in the amount of $1,000 per Unit to the Partnership (employees of Unit Corporation and its subsidiaries may elect payroll withholding). In no event will the
Partnership accept notes in exchange for a Partnership interest. Nevertheless, without any assistance of the General Partner or any of its affiliates, some Partners may choose to borrow the funds necessary to acquire a Unit and may incur interest
expense in connection with those loans. Based upon the purely factual nature of any such loans, we are unable to express an opinion with respect to the deductibility of any interest paid or incurred thereon. 
  
 TRANSACTION FEES 
  
 The Partnership may classify a portion of the fees or expense reimbursement
payments (the “Fees”) to be paid to third parties and to the General Partner or its affiliates as expenses which are deductible as organizational expenses or otherwise. There is no assurance that the Service will allow the deductibility of
such expenses and we express no opinion with respect to the allocation of the Fees to deductible and nondeductible items. 
  
 Generally, expenditures made in connection with the creation of, and with sales of interests in, a partnership will fit within one of several categories.

  
 A partnership may elect to amortize and deduct its
organizational expenses (as defined in Code Section 709(b)(2) and in Treas. Reg. Section 1.709-2(a)) ratably over a period of not less than 60 months commencing with the month the partnership begins business. Organizational expenses are expenses
which (i) are incident to the creation of the partnership, (ii) are chargeable to capital account, and (iii) are of a character which, if expended incident to the creation of a partnership having an ascertainable life, would (but for Code Section
709(a)) be amortized over 

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such life. Id. Examples of organizational expenses are legal fees for services incident to the organization of the partnership, such as negotiation
and preparation of a partnership agreement, accounting fees for services incident to the organization of the partnership, and filing fees. Treas. Reg. Section 1.709-2(a). 
  
 Under Code Section 709, no deduction is allowable for “syndication expenses,” examples of which include brokerage
fees, registration fees, legal fees of the underwriter or placement agent and the issuer (general partners or the partnership) for securities advice and for advice pertaining to the adequacy of tax disclosures in the Memorandum or private placement
memorandum for securities law purposes, printing costs, and other selling or promotional material. These costs must be capitalized. Treas. Reg. Section 1.709-2(b). Payments for services performed in connection with the acquisition of capital assets
must be amortized over the useful life of such assets. Code Section 263. 
  
 Under Code Section 195, no deduction is allowable with respect to “start-up expenditures,” although such expenditures may be capitalized and amortized over a period of not less than 60 months. Start-up
expenditures are defined as amounts (i) paid or incurred in connection with (A) investigating the creation or acquisition of an active trade or business, (B) creating an active trade or business, or (C) any activity engaged in for profit and for the
production of income before the day on which the active trade or business begins, in anticipation of such activity becoming an active trade or business, and (ii) which, if paid or incurred in connection with the operation of an existing active trade
or business (in the same field as the trade or business referred to in (i) above), would be allowable as a deduction for the taxable year in which paid or incurred. Code Section 195(c)(1). 
  
 The Partnership intends to make expense reimbursement payments to the General
Partner, as described in the Memorandum. To be deductible, compensation paid to a general partner must be for services rendered by the partner other than in his capacity as a partner or for compensation determined without regard to partnership
income. Fees which are not deductible because they fail to meet this test may be treated as special allocations of income to the recipient partner (see Pratt v. Commissioner, 550 F.2d 1023 (5th Cir. 1977)), and thereby decrease the net loss
or increase the net income among all partners. 
  
 To the extent
these expenditures described in the Memorandum are considered syndication costs, they will be nondeductible by the Partnership. To the extent attributable to organization fees (such as the amounts paid for legal services incident to the organization
of the Partnership), the expenditures may be amortizable over a period of not less than 60 months, commencing with the month the Partnership begins business, if the Partnership so elects; if no election is made, no deduction is available. Finally,
to the extent any portion of the expenditures would be treated as “start-up,” they could be amortized over a 60 month or longer period, provided the proper election was made. 
  
 Due to the inherently factual nature of the proper allocation of expenses among nondeductible syndication expenses,
amortizable organization expenses, amortizable “start-up” 

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expenditures, and currently deductible items, and because the issues involve questions concerning both the nature of the services performed and to be
performed and the reasonableness of amounts charged, we are unable to express an opinion regarding such treatment. If the Service were to successfully challenge the General Partner’s allocations, a Partner’s taxable income could be
increased, thereby resulting in increased taxes and in potential liability for interest and penalties. 
  
 BASIS AND AT RISK LIMITATIONS 
  
 A Partner’s share of Partnership losses will not be allowed as a deduction to the extent such share exceeds the amount of the Partner’s adjusted tax basis in his Units. A Partner’s initial adjusted tax
basis in his Units will generally be equal to the cash he has invested to purchase his Units. Such adjusted tax basis will generally be increased by (i) additional amounts invested in the Partnership, including his share of net income, (ii)
additional capital contributions, if any, and (iii) his share of Partnership borrowings, if any, based on the extent of his economic risk of loss for such borrowings. Such adjusted tax basis will generally be reduced, but not below zero by (i) his
share of loss, (ii) his depletion deductions on his share of oil and gas income (until such deductions exhaust his share of the basis of property subject to depletion), (iii) the amount of cash and the adjusted basis of property other than cash
distributed to him, and (iv) his share of reduction in the amount of indebtedness previously included in his basis. 
  
 In addition, Code Section 465 provides, in part, that, if an individual or a closely held C (i.e., regularly taxed) corporation engages in any
activity to which Code Section 465 applies, any loss from that activity is allowed only to the extent of the aggregate amount with respect to which the taxpayer is “at risk” for such activity at the close of the taxable year. Code Section
465(a)(1). A closely held C corporation is a corporation more than fifty percent (50%) of the stock of which is owned, directly or indirectly, at any time during the last half of the taxable year by or for not more than five (5) individuals. Code
Sections 465(a)(1)(B), 542(a)(2). For purposes of Code Section 465, a loss is defined as the excess of otherwise allowable deductions attributable to an activity over the income received or accrued from that activity. Code Section 465(d). Any such
loss disallowed by Code Section 465 shall be treated as a deduction allocable to the activity in the first succeeding taxable year. Code Section 465(a)(2). 
  
 Code Section 465(b)(1) provides that a taxpayer will be considered as being “at risk” for an activity with respect to amounts including (i) the
amount of money and the adjusted basis of other property contributed by the taxpayer to the activity, and (ii) amounts borrowed with respect to such activity to the extent that the taxpayer (A) is personally liable for the repayment of such amounts,
or (B) has pledged property, other than property used in the activity, as security for such borrowed amounts (to the extent of the net fair market value of the taxpayer’s interest in such property). No property can be taken into account as
security if such property is directly or indirectly financed by indebtedness that is secured by property used in the activity. Code Section 465(b)(2). Further, amounts borrowed by the taxpayer shall not be taken into account if such amounts are
borrowed (i) from any person who has an interest (other than an interest as a creditor) in such activity, or (ii) from a related person to a person (other than the taxpayer) having such an interest. Code Section 465(b)(3). 

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 Related persons for purposes of Code Section 465(b)(3) are defined to include related persons within
the meaning of Code Section 267(b) (which describes relationships between family members, corporations and shareholders, trusts and their grantors, beneficiaries and fiduciaries, and similar relationships), Code Section 707(b)(1) (which describes
relationships between partnerships and their partners) and Code Section 52 (which describes relationships between persons engaged in businesses under common control). Code Section 465(b)(3)(C). 
  
 Finally, no taxpayer is considered at risk with respect to amounts for which
the taxpayer is protected against loss through nonrecourse financing, guarantees, stop loss agreements, or other similar arrangements. Code Section 465(b)(4). 
  

The Code provides that a taxpayer must recognize taxable income to the extent that his “at risk” amount is reduced below zero. This
recaptured income is limited to the sum of the loss deductions previously allowed to the taxpayer, less any amounts previously recaptured. A taxpayer may be allowed a deduction for the recaptured amounts included in his taxable income if and when he
increases his amount “at risk” in a subsequent taxable year. 
  
 The Treasury has published proposed regulations relating to the at risk provisions of Code Section 465. These proposed regulations provide that a taxpayer’s at risk amount will include “personal funds” contributed by the
taxpayer to an activity. Prop. Treas. Reg. Section 1.465-22(a). “Personal funds” and “personal assets” are defined in Prop. Treas. Reg. Section 1.465-9(f) as funds and assets which (i) are owned by the taxpayer, (ii) are not
acquired through borrowing, and (iii) have a basis equal to their fair market value. 
  
 In addition to a taxpayer’s amount at risk being increased by the amount of personal funds contributed to the activity, the excess of the taxpayer’s share of all items of income received or accrued from an
activity during a taxable year over the taxpayer’s share of allowable deductions from the activity for the year will also increase the amount at risk. Prop. Treas. Reg. Section 1.465-22. A taxpayer’s amount at risk will be decreased by (i)
the amount of money withdrawn from the activity by or on behalf of the taxpayer, including distributions from a partnership, and (ii) the amount of loss from the activity allowed as a deduction under Code Section 465(a). Id. 
  
 The Partners will purchase Units by tendering cash (or payroll deductions) to
the Partnership. To the extent the cash contributed constitutes the “personal funds” of the Partners, the Partners should be considered at risk with respect to those amounts. To the extent the cash contributed constitutes “personal
funds,” in our opinion, neither the at risk rules nor the adjusted basis rules will limit the deductibility of losses generated from the Partnership. 

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 PASSIVE LOSS AND CREDIT LIMITATIONS 
  
 A. Introduction 
  
 Code Section 469 provides that the deductibility of losses generated from passive activities will be limited for certain
taxpayers. The passive activity loss limitations apply to individuals, estates, trusts, and personal service corporations as well as, to a lesser extent, closely held C corporations. Code Section 469(a)(2). 
  
 The definition of a “passive activity” generally encompasses all
rental activities as well as all activities with respect to which the taxpayer does not “materially participate.” Code Section 469(c). Notwithstanding this general rule, however, the term “passive activity” does not include
“any working interest in any oil or gas property which the taxpayer holds directly or through an entity which does not limit the liability of the taxpayer with respect to such interest.” Code Section 469(c)(3)(4). 
  
 A passive activity loss (“PAL”) is defined as the amount (if any)
by which the aggregate losses from all passive activities for the taxable year exceed the aggregate income from all passive activities for such year. Code Section 469(d)(1). 
  
 Classification of an activity as passive will result in the income and expenses generated therefrom being treated as
“passive” except to the extent that any of the income is “portfolio” income and except as otherwise provided in regulations. Code Section 469(e)(1)(A). Portfolio income is income from, inter alia, interest, dividends. and
royalties not derived in the ordinary course of a trade or business. Income that is neither passive nor portfolio is “net active income.” Code Section 469(e)(2)(B). 
  
 With respect to the deductibility of PALs, individuals and personal service corporations will be entitled to deduct such
amounts only to the extent of their passive income whereas closely held C corporations (other than personal service corporations) can offset PALs against both passive and net active income, but not against portfolio income. Code Section 469(a)(1),
(e)(2). In calculating passive income and loss, however, all activities of the taxpayer are aggregated. Code Section 469(d)(1). PALs disallowed as a result of the above rules will be suspended and can be carried forward indefinitely to offset future
passive (or passive and active, in the case of a closely held C corporation) income. Code Section 469(b). 
  
 Upon the disposition of an entire interest in a passive activity in a fully taxable transaction not involving a related party, any passive loss that was
suspended by the provisions of the Code Section 469 passive activity rules is deductible from either passive or non-passive income. The deduction must be reduced, however, by the amount of income or gain realized from the activity in previous years.

  
 As noted above, a passive activity includes an activity with
respect to which the taxpayer does not “materially participate.” A taxpayer will be considered as materially participating in a 

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venture only if the taxpayer is involved in the operations of the activity on a “regular, continuous, and substantial” basis. Code Section
469(h)(1). With respect to the determination as to whether a taxpayer’s participation in an activity is material, temporary regulations issued by the Service provide that, except for limited partners in a limited partnership, an individual will
be treated as materially participating in an activity if and only if (i) the individual participates in the activity for more than 500 hours during such year, (ii) the individual’s participation in the activity for the taxable year constitutes
substantially all of the participation in such activity of all individuals for such year, (iii) the individual participates in the activity for more than 100 hours during the taxable year, and such individual’s participation in such activity is
not less than the participation in the activity of any other individual for such year, (iv) the activity is a trade or business activity of the individual, the individual participates in the activity for more than 100 hours during such year, and the
individual’s aggregate participation in all significant participation activities of this type during the year exceeds 500 hours, (v) the individual materially participated in the activity for 5 of the last 10 years, or (vi) the activity is a
personal service activity and the individual materially participated in the activity for any 3 preceding years. Temp. Treas. Reg. Section 1.469-5T(a). 
  
 Notwithstanding the above, and except as may be provided in regulations, Code Section 469(h)(2) provides that no limited partnership interest will be
treated as an interest with respect to which a taxpayer materially participates. The temporary regulations create several exceptions to this rule and provide that a limited partner will not be treated as not materially participating in an activity
of the partnership of which he is a limited partner if the limited partner would be treated as materially participating for the taxable year under paragraph (a)(1), (5), or (6) of Treas. Reg. Section 1.469-5T (as described in (i), (v), and (vi) of
the above paragraph) if the individual were not a limited partner for such taxable year. Temp. Treas. Reg. Section 1.469-5T(e). For purposes of this rule, a partnership interest of an individual will not be treated as a limited partnership interest
for the taxable year if the individual is an Additional General Partner in the partnership at all times during the partnership’s taxable year ending with or within the individual’s taxable year. Id. 
  
 B. Limited Partner Interests 
  
 If an investor invests in the Partnership as a Limited Partner, in our
opinion, his distributive share of the Partnership’s losses will be treated as PALs, the availability of which will be limited to his passive income thereon. If the Limited Partner does not have sufficient passive income to utilize the PALs,
the disallowed PALs will be suspended and may be carried forward (but not back) to be deducted against passive income arising in future years. Further, upon the complete disposition of the interest to an unrelated party in a fully taxable
transaction, such suspended losses will be available, as described above. 
  
 Regarding Partnership income, Limited Partners should generally be entitled to offset their distributive shares of such income with deductions from other passive activities, except to the extent such Partnership
income is portfolio income. Since gross income from interest, dividends, annuities, and royalties not derived in the ordinary course of a trade or business is not 

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passive income, a Limited Partner’s share of income from royalties, income from the investment of the Partnership’s working capital, and other
items of portfolio income will not be treated as passive income. In addition, Code Section 469(1)(3) grants the Secretary of the Treasury the authority to prescribe regulations requiring net income or gain from a limited partnership or other passive
activity to be treated as not from a passive activity. 
  
 C. Publicly Traded
Partnerships 
  
 Notwithstanding the above, Code Section
469(k) treats net income from PTPs as portfolio income under the PAL rules. Further each partner in a PTP is required to treat any losses from a PTP as separate from income and loss from any other PTP and also as separate from any income or loss
from passive activities. Id. Losses attributable to an interest in a PTP that are not allowed under the passive activity rules are suspended and carried forward, as described above. Further, upon a complete taxable disposition of an interest
in a PTP, any suspended losses are allowed (as described above with respect to the passive loss rules). As noted above, we have opined that the Partnership will not be a PTP. 
  
 In the event the Partnership were treated as a PTP, any net income would be treated as portfolio income and each
Partner’s loss therefrom would be treated as separate from income and loss from any other PTP and also as separate from any income or loss from passive activities. Since the Partnership should not be treated as a PTP, the provisions of Code
Section 469(k), in our opinion, will not apply to the Partners in the manner outlined above prior to the time that such Partnership becomes a PTP. However, unlike the PTP rules of Code Section 7704, the passive activity rules of Code Section 469 do
not provide an exception for partnerships that pass the 90% test of Code Section 7704. Accordingly, if the Partnership were to be treated as a PTP under the passive activity rules, passive losses could be used only to offset passive income from the
Partnership. 
  
 ALTERNATIVE MINIMUM TAX 
  
 For taxable years beginning after December 31, 1992, Code Section 55 imposes
on noncorporate taxpayers a two-tiered, graduated rate schedule for alternative minimum tax (“AMT”) equal to the sum of (i) 26% of so much of the “taxable excess” as does not exceed $175,000, plus (ii) 28% of so much of the
“taxable excess” as exceeds $175,000. Code Section 55(b)(1)(A)(i). “Taxable excess” is defined as so much of the alternative minimum taxable income (“AMTI”) for the taxable year as exceeds the exemption amount. Code
Section 55(b)(1)(A)(ii). AMTI is generally defined as the taxpayer’s taxable income, increased or decreased by certain adjustments and items of tax preference. Code Section 55(b)(2). 
  
 The exemption amount for noncorporate taxpayers is (i) $58,000 in the case of a joint return or a surviving spouse, (ii)
$40,250 in the case of an individual who is not a married individual or a surviving spouse, and (iii) $29,000 in the case of a married individual who files a separate return or an estate or trust. Such amounts are phased out as a taxpayer’s
AMTI increases above certain levels. Code Section 55(d)(1) and (3). Individuals subject to the AMT are 

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generally allowed a credit, equal to the portion of the AMT imposed by Code Section 55 arising as a result of deferral preferences for use against the
taxpayer’s future regular tax liability (but not the minimum tax liability). 
  
 Under the AMT provisions, adjustments and items of tax preference that may arise from a Partner’s acquisition of an interest in the Partnership include the following: 
  
 1. For taxable years beginning after December 31, 1992,
taxpayers which do not meet the definition of an integrated oil company as defined in Code Section 291(b)(4) are not subject to the preference item for “excess IDC.” Code Section 57(a)(2)(E)(i). The benefit of the elimination of the
preference is limited in any taxable year to an amount equal to 40 percent of the alternative minimum taxable income for the year computed as if the prior law “excess IDC” preference item has not been eliminated. Code Section
57(a)(2)(E)(ii). Excess IDC is defined as the excess of (i) IDC paid or incurred (other than costs incurred in drilling a nonproductive well) with respect to which a deduction is allowable under Code Section 263(c) for the taxable year over (ii) the
amount which would have been allowable for the taxable year if such costs had been capitalized and (I) amortized over a 120 month period beginning with the month in which production from such well begins or (II) recovered through cost depletion.
Code Section 57(a)(2)(B). However, any portion of the IDC to which an election under Code Section 59(e) applies will not be treated as an item of tax preference under Code Section 57(a). Code Section 59(e)(6). With respect to IDC paid or incurred,
corporate and individual taxpayers are allowed to make the Code Section 59(e) election and, for regular tax and AMT purposes, deduct such expenditures over the 60 month period beginning with the month in which such expenditure is paid or incurred.
Code Section 59(e)(1). 
  
 2. For taxable years
beginning after December 31, 1992, the preference item for excess depletion is repealed for other than integrated oil companies. Code Section 57(a)(1). 
  
 3. Each Partner’s AMTI will be increased (or decreased) by the amount by which the depreciation deductions allowable under Code
Sections 167 and 168 with respect to such property exceeds (or is less than) the depreciation determined under the alternative depreciation system using the one hundred fifty percent (150%) declining balance method switching to the straight-line
method, when that produces a greater deduction, in lieu of the straight-line method otherwise prescribed by the ADS. Code Section 56(a)(1). 
  
 Due to the inherently factual nature of the applicability of the AMT to a Partner, we are unable to express an opinion with respect to such issues. Due to
the potentially significant impact of a purchase of Units on an investor’s tax liability, investors should discuss the implications of an investment in the Partnership on their regular and AMT liabilities with their tax advisors prior to
acquiring Units. 

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 GAIN OR LOSS ON SALE OF PROPERTIES 
  
 Gain from the sale or other disposition of property is realized to the extent
of the excess of the amount realized therefrom over the property’s adjusted basis; conversely, loss is realized in an amount equal to the excess of the property’s adjusted basis over the amount realized from such a disposition. Code
Section 1001(a). The amount realized is defined as the sum of any money received plus the fair market value of the property (other than money) received. Code Section 1001(b). Accordingly, upon the sale or other disposition of the Partnership
properties, the Partners will realize gain or loss to the extent of their pro rata share of the difference between the Partnership’s adjusted basis in the property at the time of disposition and the amount realized upon disposition. In the
absence of nonrecognition provisions, any gain or loss realized will be recognized for federal income tax purposes. 
  
 Gain or loss recognized upon the disposition of property used in a trade or business and held for more than one year will be treated as long term capital
gain or as ordinary loss. Code Section 1231(a). Notwithstanding the above, any gain realized may be taxed as ordinary income under one of several “recapture” provisions of the Code or under the characterization rules relating to
“dealers” in personal property. 
  
 Code Section 1254
generally provides for the recapture of capital gains, arising from the sale of property which was placed in service after 1986, as ordinary income to the extent of the lesser of (i) the gain realized upon sale of the property, or (ii) the sum of
(A) all IDC previously deducted and (B) all depletion deductions that reduced the property’s basis. Code Section 1254(a)(1). 
  
 Ordinary income may also result from the recapture, pursuant to Code Section 1245, of depreciation on the Partnership properties. Such recapture is the
amount by which (i) the lower of (A) the recomputed basis of the property, or (B) the amount realized on the sale of the property exceeds (ii) the property’s adjusted basis. Code Section 1245(a)(1). Recomputed basis is generally the
property’s adjusted basis increased by depreciation and amortization deductions previously claimed with respect to the property. Code Section 1245(a)(2). 
  

GAIN OR LOSS ON SALE OF UNITS 
  
 It the Units are capital assets in the hands of the Partners, gain or loss realized by any such holders on the sale or other disposition of a Unit will be
characterized as capital gain or capital loss. Code Section 1221. Such gain or loss will be a long term capital gain or loss if the Unit is held for more than one year, or a short term capital gain or loss if held for one year or less. However, the
portion of the amount realized by a Partner in exchange for a Unit that is attributable to the Partner’s share of the Partnership’s “unrealized receivables” or “substantially appreciated inventory items” will be treated
as an amount realized from the sale or exchange of property other than a capital asset. Code Section 751. 

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 Unrealized receivables are defined in Code Section 751(c) to include “ . . . oil [or] gas . . .
property . . . to the extent of the amount which would be treated as gain to which section . . . 1245(a) . . . or 1254(a) would apply if . . . such property had been sold by the partnership at its fair market value.” A sale by the Partnership
of the Partnership’s properties could give rise to treatment of the gain thereunder as ordinary income as a result of Code Sections 1245(a) or 1254(a). Accordingly, gain recognized by a Partner on the sale of a Unit would be taxed as ordinary
income to the Partner to the extent of his share of the Partnership’s gain on property that would be recaptured, upon sale, under those statutes. 
  
 Substantially appreciated inventory items are those “inventory items” noted below, the fair market value of which exceeds 120% of the adjusted
basis to the partnership of such property, excluding any such inventory property acquired with a principal purpose of avoiding Section 751. Code Section 751(d)(1). Property treated as an “inventory item” for purposes of Code Section 751
includes (i) stock in trade of the partnership or other property of a kind which would properly be included in its inventory if on hand at the end of the taxable year, (ii) property held by the partnership primarily for sale to customers in the
ordinary course of its trade or business, and (iii) any other partnership property which would constitute neither a capital asset nor property used in a trade or business under Code Section 1231. Code Sections 751(d)(2) and 1221(1). 
  
 Under the aforementioned provisions, a Partner would recognize ordinary
income with respect to any deemed sale of assets under Code Section 751; further, this ordinary income may be recognized even if the total amount realized on the sale of a Unit is equal to or less than the Partner’s basis in the Unit.

  
 Any partner who sells or exchanges interests in a partnership
holding unrealized receivables (which include IDC recapture and other items) or certain inventory items must notify the partnership of such transaction in accordance with Regulations under Code Section 6050K and must attach a statement to his tax
return reflecting certain facts regarding the sale or exchange. Regulations promulgated by the Service provide that such notice to the partnership must be given in writing within 30 days of the sale or exchange (or, if earlier, by January 15 of the
calendar year following the calendar year in which the exchange occurred), and must include names, addresses, and taxpayer identification numbers (if known) of the transferor and transferee and the date of the exchange. Code Section 6721 provides
that persons who fail to furnish this information to the partnership will be penalized $50 for each such failure, or, if such failure is due to intentional disregard to the filing requirement, the person will be penalized the greater of (i) $100 or
(ii) 10% of the aggregate amount to be reported. Furthermore, a partnership is required to notify the Service of any sale or exchange of interests of which it has notice, and to report the names and addresses of the transferee and the transferor,
along with all other required information. The partnership also is required to provide copies of the information it provides to the Service to the transferor and the transferee. 

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 The tax consequences to an assignee purchaser of a Unit from a Partner are not described herein. Any
assignor of a Unit should advise his assignee to consult his own tax advisor regarding the tax consequences of such assignment. 
  
 PARTNERSHIP DISTRIBUTIONS 
  
 Under the Code, any increase in a partner’s share of partnership liabilities, or any increase in such partner’s individual liabilities by reason
of an assumption by him of partnership liabilities is considered to be a contribution of money by the partner to the partnership. Similarly, any decrease in a partner’s share of partnership liabilities or any decrease in such partner’s
individual liabilities by reason of the partnership’s assumption of such individual liabilities will be considered as a distribution of money to the partner by the partnership. Code Section 752(a), (b). 
  
 The Partners’ adjusted bases in their Units will initially consist of
the cash they contribute to the Partnership. Their bases will be increased by their share of Partnership income and additional contributions and decreased by their share of Partnership losses and distributions. To the extent that such actual or
constructive distributions are in excess of a Partner’s adjusted basis in his Partnership interest (after adjustment for contributions and his share of income and losses of the Partnership), that excess will generally be treated as gain from
the sale of a capital asset. In addition, gain could be recognized to a distributee partner upon the disproportionate distribution to a partner of unrealized receivables, substantially appreciated inventory or, in some cases, Code Section 731(c)
marketable securities, i.e., actively traded financial instruments, foreign currencies or interests in certain defined properties. 
  
 PARTNERSHIP ALLOCATIONS 
  
 Allocations—General. Generally, a partner’s taxable income is increased or decreased by his ratable share of partnership income or loss. Code
Section 701. However, the availability of these losses may be limited by the at risk rules of Code Section 465, the passive activity rules of Code Section 469, and the adjusted basis provisions of Code Section 704(d). 
  
 Code Section 704(b) provides that if a partnership agreement does not provide
for the allocation of each partner’s distributive share of partnership income, gain, loss, deduction, or credit, or if the allocation of such items under the partnership agreement lacks “substantial economic effect,” then each
partner’s share of those items must be allocated “in accordance with the partner’s interest in the partnership.” 
  
 As discussed below, regulations under Code Section 704(b) define substantial economic effect and prescribe the manner in which partners’ capital
accounts must be maintained in order for the allocations contained in a partnership agreement to be respected. Notwithstanding these provisions, special rules apply with respect to nonrecourse deductions since, under the Treasury Regulations,
allocations of losses or deductions attributable to nonrecourse liabilities cannot have economic effect. 

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 The Service may contend that the allocations contained in the Partnership Agreement do not have
substantial economic effect or are not in accordance with the Partners’ interests in the Partnership and may seek to reallocate these items in a manner that will increase the income or gain or decrease the deductions allocable to a Partner. We
are of the opinion that, to the extent provided herein, if challenged by the Service on this matter, the Partners’ distributive shares of Partnership income, gain, loss, deduction, or credit will be determined and allocated substantially in
accordance with the terms of the Partnership Agreement and have substantial economic effect. 
  
 Substantial Economic Effect. Although a partner’s share of partnership income, gain, loss, deduction, and credit is generally determined in accordance with the partnership agreement, this share will be
determined in accordance with the partner’s interest in the partnership (determined by taking into account all facts and circumstances) and not by the partnership agreement if the partnership allocations do not have “substantial economic
effect” and if the allocations are not respected under the nonrecourse deduction provisions of the regulations. Code Section 704(b); Treas. Reg. Sections 1.704-1(b)(2)(i), 1.704-2. 
  
 Treasury regulations provide that: 
  

In order for an allocation to have economic effect, it must be consistent with the underlying economic arrangement of the partners.
This means that in the event there is an economic benefit or economic burden that corresponds to an allocation, the partner to whom the allocation is made must receive such economic benefit or bear such economic burden. 
  
 Treas. Reg. Section 1.704-1(b)(2)(ii). The Regulations further provide that an allocation
will have economic effect only if, throughout the full term of the partnership, the partnership agreement provides (i) for the determination and maintenance of partner’s capital accounts in accordance with specified rules contained therein,
(ii) upon liquidation of the partnership or a partner’s interest in the partnership, liquidating distributions are required to be made in accordance with the positive capital account balances of the partners after taking into account all
capital account adjustments for the taxable year of the liquidation, and (iii) either (A) a partner with a deficit balance in his capital account following the liquidation is unconditionally obligated to restore the amount of such deficit balance to
the partnership by the end of the taxable year of liquidation, or (B) the partnership agreement contains a qualified income offset (“QIO”) provision as provided in Treas. Reg. Section 1.714-1(b)(2)(ii)(d). Treas. Reg. Sections
1.704-1(b)(2)(ii)(b) and 1.704-1(b)(2)(ii)(d). 
  
 The capital
account maintenance rules generally mandate that each partner’s capital account be increased by (i) money contributed by the partner to the partnership, (ii) the fair market value (net of liabilities) of property contributed by the partner to
the partnership, and (iii) allocations to the partner of partnership income and gain. Further, such capital account must be decreased by (i) money distributed to the partner from the partnership, (ii) the fair market value (net of liabilities) of
property distributed to the partner from the partnership, and (iii) allocations to the partner of partnership losses and deductions. Treas. Reg. Section 1.704-1(b)(2)(iv). 

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 Treas. Reg. Section 1.714-1(b)(2)(iii) provides that an economic effect of an allocation is
“substantial” if there is a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences. The economic effect of an allocation
is not substantial if: 
  
 at the time the allocation becomes
part of the partnership agreement, (1) the after-tax economic consequences of at least one partner may, in present value terms, be enhanced compared to such consequences if the allocation (or allocations) were not contained in the partnership
agreement, and (2) there is a strong likelihood that the after-tax economic consequences of no partner will, in present value terms, be substantially diminished compared to such consequences if the allocation (or allocations) were not contained in
the partnership agreement. In determining the after-tax economic benefit or detriment to a partner, tax consequences that result from the interaction of the allocation with such partner’s tax attributes that are unrelated to the partnership
will be taken into account. 
  
 Treas. Reg. 1.704-1(b)(2)(iii)(a). 

 
 While the Service stated that it will not rule on whether an allocation
provision in a partnership agreement has substantial economic effect, several Technical Advice Memoranda (“TAMs”) shed light on the Service’s position on such matter. Notwithstanding the potential similarity between TAMs and a
taxpayer’s particular fact pattern, it should be noted that TAMs may not be used or cited as precedent. Code Section 6110(j)(3), Treas. Reg. Sections 301.6110-2(a) and -7(b). Nevertheless, TAMs do serve to illustrate the Service’s position
on certain specific cases. The TAMs relating to substantial economic effect focus on the tax avoidance purpose of any such above-described allocations and on the partnership plan for distributions upon liquidation. Illustrative of the Service’s
approach is TAM 8008054, in which the Service concluded that an allocation to the partners solely of items that the partnership had elected to expense (IDC) had as its principal purpose tax avoidance. The Service suggested that, had the allocation
affected the parties’ liquidation rights, the allocation would have had substantial economic effect: “In general, substantial economic effect has been found where all allocations of items of income, gain, loss, deduction or credit increase
or decrease the respective capital accounts of the partners and distribution of assets made upon liquidation is made in accordance with capital accounts.” The ruling noted that the investors “should have been allocated their share of costs
over the intangible drilling costs.” Id. The question whether economic effect is “substantial” is one of fact which may depend in part on the timing of income and deductions and on consideration of the investors’ tax
attributes unrelated to their investment in Units, and thus is not a question upon which a legal opinion can ordinarily be expressed. However, to the extent the tax brackets of all Partners do not differ at the time the allocation becomes part of
the partnership agreement, the economic effect of the allocation provisions should be considered to be substantial. 

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 Code Section 613A(c)(7)(D) requires that the basis of oil and gas properties owned by a partnership
be allocated to the partners in accordance with their interests in the capital or income of the partnership. Final Regulations issued under Code Section 613A(c)(7)(D) indicate that such basis must be allocated in accordance with the partners’
interests in the capital of the partnership if their interests in partnership income vary over the life of the partnership for any reason other than for reasons such as the admission of a new partner. Reg. Section 1.613A-3(e)(2). The terms
“capital” and “income” are not defined in the Code or in the Regulations under Section 613A. The Treasury Regulations under Code Section 704 indicate that if all partnership allocations of income, gain, loss, and deduction (or
items thereof) have substantial economic effect, an allocation of the adjusted basis of an oil or gas property among the partners will be deemed to be made in accordance with the partners’ interests in partnership capital or income and will
accordingly be recognized. 
  
 Pursuant to the Partnership
Agreement, (i) allocations will be made as mandated by the Treasury Regulations, (ii) liquidating distributions will be made in accordance with positive capital account balances, and (iii) a “qualified income offset” provision applies.
However, while capital will be ultimately owned by the Limited Partners in the Limited Partners’ Percentage and by the General Partner in the General Partner’s Percentage, IDC and other tax items will be allocated 99% to the Limited
Partners and 1% to the General Partner until the Limited Partner Capital Contributions are entirely expended and thereafter 100% to the General Partner. Except with respect to those excess allocations, under the Partnership Agreement, the basis in
oil and gas properties will be allocated in proportion to each Partner’s respective share of the costs which entered into the Partnership’s adjusted basis for each depletable property. Such allocations of basis appear reasonable and in
compliance with the Treasury Regulations under Section 704. Nevertheless, the Service may contend that the allocation to the Limited Partners of a percentage of Partnership IDC in excess of the Limited Partners’ Percentage or the allocation to
the General Partner of other tax items in excess of the General Partner’s Percentage is invalid and may reallocate such excess IDC or other items to the other Partners. Any such reallocation could increase a Limited Partner’s tax
liability. However, no assurance can be given, and we are unable to express an opinion, as to whether any special allocation of an item which is dependent upon basis in an oil and gas property will be recognized by the Service. 
  
 Nonrecourse Deductions. As noted above, an allocation of loss or
deduction attributable to nonrecourse liabilities of a partnership cannot have economic effect because only the creditor bears the economic burden that corresponds to such an allocation. Nevertheless the Temporary Regulations provide a test under
which certain allocations of nonrecourse deductions will be deemed to be in accordance with the partners’ interests in the partnership. 
  
 Nonrecourse deduction allocations will be deemed to be made in accordance with partners partnership interests if, and only if, four requirements are
satisfied. First, the partners’ capital accounts must be maintained properly and the distribution of liquidation proceeds must be in accordance with the partners’ capital account balances. Second, beginning in the first taxable year in
which there are nonrecourse deductions, and thereafter throughout the full term of 

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the partnership, the partnership agreement must provide for allocation of nonrecourse deductions among the partners in a manner that is reasonably consistent
with allocations which have substantial economic effect of some other significant partnership item attributable to the property securing nonrecourse liabilities of the partnership. Third, beginning in the first taxable year of the partnership in
which the partnership has nonrecourse deductions or makes a distribution of proceeds of a nonrecourse liability that are allocable to an increase in minimum gain, and thereafter throughout the full term of the partnership, the partnership agreement
must contain a “minimum gain chargeback.” A partnership agreement contains a “minimum gain chargeback” if, and only if, it provides that, subject to certain exceptions, in the event there is a net decrease in partnership minimum
gain during a partnership taxable year, the partners must be allocated items of partnership income and gain for that year equal to each partner’s share of the net decrease in partnership minimum gain during such year. A partner’s share of
the net decrease in partnership minimum gain is the amount of the total net decrease multiplied by the partner’s percentage share of the partnership’s minimum gain at the end of the immediately preceding taxable year. A partner’s
share of any decrease in partnership minimum gain resulting from a revaluation of partnership property (which would not cause a minimum gain chargeback) equals the increase in the partner’s capital account attributable to the revaluation to the
extent the reduction in minimum gain is caused by such revaluation. Similar rules apply with regard to partner nonrecourse liabilities and associated deductions. The fourth requirement of the nonrecourse allocation test provides that all other
material allocations and capital account adjustments under the partnership agreement must be recognized under the general allocation requirements of the regulations under IRC Section 704(b). 
  
 Under the Treasury Regulations, partners generally share nonrecourse
liabilities in accordance with their interests in partnership profits. However, the Treasury Regulations generally require that nonrecourse liabilities be allocated among the partners first to reflect the partners’ share of minimum gain and
Code Section 704(c) minimum gain. Any remaining nonrecourse liabilities are generally to be allocated in proportion to the partners’ interests in partnership profits. 
  
 The Partnership Agreement contains a minimum gain chargeback. Further, the Partnership Agreement provides for the allocation
of nonrecourse liabilities and deductions attributable thereto among the Partners first, in accordance with their respective shares of partnership minimum gain (within the meaning of Regulation Section 1.704-2(b)(2)); second, to the extent of each
such Partner’s gain under Code Section 704(c) if the Partnership were to dispose of (in a taxable transaction) all Partnership property subject to one or more nonrecourse liabilities of the Partnership in full satisfaction of such liabilities
and for no other consideration; and third, in accordance with the Partners’ proportionate shares in the Partnership’s profits. Regulation Section 1.752-3. For this purpose, the Partnership Agreement provides for the allocation of excess
nonrecourse deductions in the Limited Partners’ Percentage to the Limited Partners and in the General Partner’s Percentage to the General Partner. 
  
 Retroactive Allocations. To prevent retroactive allocations of partnership tax attributes to partners entering into a partnership late in the tax
year, Code Section 706(d) provides that a 

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partner’s distributive share of such attributes is to be determined by the use of methods prescribed by the Secretary of the Treasury which take into
account the varying interests of the partners during the taxable year. The Partnership Agreement provides that each Partner’s allocation of tax items other than “allocable cash basis items” is to be determined under a method permitted
by Code Section 706(d) and the regulations thereunder. 
  
 PROFIT MOTIVE 
  
 The existence of economic,
non-tax motives for entering into the Transaction is essential if the Partners are to obtain the tax benefits associated with an investment in the Partnership. 
  

Code Section 183(a) provides that where an activity entered into by an individual is not engaged in for profit, no deduction attributable to that
activity will be allowed except as provided therein. Should it be determined that a Partner’s activities with respect to the Transaction fall within the “not for profit” ambit of Code Section 183, the Service could disallow all or a
portion of the deductions and credits generated by the Partnership’s activities. 
  
 Code Section 183(d) generally provides for a presumption that an activity is entered into for profit within the meaning of the statute where gross income from the activity exceeds the deductions attributable to such
activity for three or more of the five consecutive taxable years ending with the taxable year in question. At the taxpayer’s election, such presumption can relate to three or more of the taxable years in the 5-year period beginning with the
taxable year in which the taxpayer first engages in the activity. Whether an activity is engaged in for profit is determined under Code Sections 162 (relating to trade or business deductions) and 212(1) and (2) (relating to income producing
deductions) except insofar as the above-described presumption applies. Treas. Reg. Section 1.183-1(a). 
  
 To establish that he is engaged in either a trade or business or an income producing activity, a Partner must be able to prove that he is engaged in the
Transaction with an “actual and honest profit objective,” Fox v. Commissioner, 80 T.C. 972, 1006 (1983), aff’d sub nom., Barnard v. Commissioner, 731 F.2d 230 (4th Cir. 1984), and that his profit objective is bona
fide. Bessenyey v. Commissioner, 45 T.C. 261, 274 (1965), aff’d, 379 F.2d 252 (2d Cir. 1967), cert. denied, 389 U.S. 931 (1967). The inquiry turns on whether the primary purpose and intention of the Partner in engaging in the
activity is, in fact, to make a profit apart from tax considerations. Hager v. Commissioner, 76 T.C. 759, 784. Such objective need not be reasonable, only honest, and the question of objective is to be determined from all the facts and
circumstances. Sutton v. Commissioner, 84 T.C. 210 (1985), aff’d, 788 F.2d 695 (11th Cir. 1986). Among the factors that will normally be considered are: (i) the manner in which the taxpayer carries on the activity, (ii) the
expertise of the taxpayer or his advisors, (iii) the time and effort expended by the taxpayer in carrying on the activity, (iv) whether an expectation exists that the assets used in the activity may appreciate in value, (v) the success of the
taxpayer in carrying on similar or dissimilar activities, (vi) the taxpayer’s history of income or losses with respect to the activity, (vii) the amount of occasional profits, if any, which are earned, and (viii) the financial status of the
taxpayer. Treas. Reg. Section 1.183-2(b). Where application of 

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such factors to a particular activity is difficult, however, the Court will consider the totality of the circumstances instead. Estate of Baron v.
Commissioner, 83 T.C. 542 (1984), aff’d 798 F.2d 65 (2d Cir. 1986). 
  
 As noted, the issue is one of fact to be resolved not on the basis of any one factor but on the basis of all the facts and circumstances. Treas. Reg. Section 1.183-2(b). Greater weight is given to objective facts than
the parties’ mere statements of their intent. Siegel v. Commissioner, 78 T.C. 659, Engdahl v. Commissioner, 72 T.C. 659 (1979). Nevertheless, the Courts have recognized, in applying Code Section 183, that “a taxpayer has the
right to engage in a venture which has economic substance even though his motivation in the early years of the venture may have been to obtain a deduction to offset taxable income.” Lemmen v. Commissioner, 77 T.C. 1326, 1346 (1981),
acq., 1983-1 C.B. 1. 
  
 Due to the inherently factual
nature of a Partner’s intent and motive in engaging in the Transaction, we do not express an opinion as to the ultimate resolution of this issue in the event of a challenge by the Service. Partners must, however, seek to make a profit from
their activities with respect to the Transaction beyond any tax benefits derived from those activities or risk losing those tax benefits. 
  
 TAX AUDITS 
  
 Subchapter C of Chapter 63 of the Code provides that administrative proceedings for the assessment and collection of tax deficiencies attributable to a
partnership must be conducted at the partnership, rather than the partner, level. Partners will be required to treat Partnership items of income, gain, loss, deduction, and credit in a manner consistent with the treatment of each such item on the
Partnership’s returns unless such Partner files a statement with the Service identifying the inconsistency. If the Partnership is audited, the tax treatment of each item will be determined at the Partnership level in a unified partnership
proceeding. Conforming adjustments to the Partners’ own returns will then occur unless such partner can establish a basis for inconsistent treatment (subject to waiver by the Service). 
  
 The General Partner will be designated the “tax matters partner”
(“TMP”) for the Partnership and will receive notice of the commencement of a Partnership proceeding and notice of any administrative adjustments of Partnership items. The TMP is entitled to invoke judicial review of administrative
determinations and to extend the period of limitations for assessment of adjustments attributable to Partnership items. Each Partner will receive notice of the administrative proceedings from the TMP and will have the right to participate in the
administrative proceeding pursuant to tax requirements of Treasury Regulation Section 301.6223(g) unless the Partner waives such rights. 
  
 The Code provides that, subject to waiver, partners will receive notice of the administrative proceedings from the Service and will have the right to
participate in the administrative proceedings. However, the Code also provides that if a partnership has 100 or more partners, the partners with less than a 1% profits interest will not be entitled to receive 

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notice from the Service or participate in the proceedings unless they are members of a “notice group” (a group of partners having in the aggregate
a 5% or more profits interest in the partnership that requires the Service to send notice to the group and that designates one of their members to receive notice). Any settlement agreement entered into between the Service and one or more of the
partners will be binding on such partners but will not be binding on the other partners, except that settlement by the TMP may be binding on certain partners, as described below. The Service must, on request, offer consistent settlement terms to the
partners who had not entered into the earlier settlement agreement. If a partnership has more than 100 partners, the TMP is empowered under the Code to enter into binding settlement agreements on behalf of the partners with a less than 1% profits
interest unless the partner is a member of a notice group or notifies the Service that the TMP does not have the authority to bind the partner in such a settlement. 
  
 The costs incurred by a Partner in responding to an administrative proceeding will be borne solely by such Partner.

  
 PENALTIES 
  
 Under IRC Section 6662, a taxpayer will be assessed a penalty equal to twenty
percent (20%) of the portion of an underpayment of tax attributable to negligence, disregard of a rule or regulation or a substantial understatement of tax. “Negligence” includes any failure to make a reasonable attempt to comply with the
tax laws. IRC Section 6662(c). The regulations further provide that a position with respect to an item is attributable to negligence if it lacks a reasonable basis. Treas. Reg. Section 1.6662-3(b)(1). Negligence is strongly indicated where, for
example, a partner fails to comply with the requirements of IRC Section 6662, which requires that a partner treat partnership items on its return in a manner that is consistent with the treatment of such items on the partnership return. Treas. Reg.
Section 1.6662-3(b)(1)(iii). The term “disregard” includes any careless, reckless or intentional disregard of rules or regulations. Treas. Reg. Section 1.6662-3(b)(2). A taxpayer who takes a position contrary to a revenue ruling or a
notice will be subject to a penalty for intentional disregard if the contrary position fails to possess a realistic possibility of being sustained on its merits. Treas. Reg. Section 1.6562-3(b)(2). An “understatement” is defined as the
excess of the amount of tax required to be shown on the return of the taxable year over the amount of the tax imposed that is actually shown on the return, reduced by any rebate. IRC Section 6662(d)(2)(A). An understatement is
“substantial” if it exceeds the greater of ten percent (10%) of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 in the case of certain corporations). IRC Section 6662(d)(1)(A) and (B). 
  
 Generally, for tax returns with due dates (determined without regard to
extensions) after December 31, 1993, the amount of an understatement is reduced by the portion thereof attributable to (i) the tax treatment of any item by the taxpayer if there is or was substantial authority for such treatment, or (ii) any item if
the relevant facts affecting the item’s tax treatment are adequately disclosed in the return or in a statement attached to the return, and there is a reasonable basis for the tax treatment of such item by the taxpayer. IRC Section 6662(d).

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Disclosure will generally be adequate if made on a properly completed Form 8275 (Disclosure Statement) or Form 8275R (Regulation Disclosure Statement).
Treas. Reg. Section 1.6662-4(f). However, in the case of “tax shelters,” there will be a reduction of the understatement only to the extent it is attributable to the treatment of an item by the taxpayer with respect to which there is or
was substantial authority for such treatment and only if the taxpayer reasonably believed that the treatment of such item by the taxpayer was more likely than not the proper treatment. Moreover, under the Uruguay Round Table Agreements Act, a
corporation must generally satisfy a higher standard to avoid a substantial understatement penalty in the case of a tax shelter. IRC Section 6662(d)(2)(C)(ii). The term “tax shelter” is defined for purposes of Code Section 6662 as a
partnership or other entity, any investment plan or arrangement, or any other plan or arrangement, the principal purpose of which is the avoidance or evasion of federal income tax. IRC Section 6662(d)(2)(C)(ii). It is important to note that this
definition of “tax shelter” differs from that contained in Code Sections 461 and 6111, as discussed above. A tax shelter item includes an item of income, gain, loss, deduction, or credit that is directly or indirectly attributable to a
partnership that is formed for the principal purpose of avoiding or evading federal income tax. The existence of substantial authority is determined as of the time the taxpayer’s return is filed or on the last day of the taxable year to which
the return relates and not when the investment is made. Treas. Reg. Section 1.6662-4(d)(3)(iv)(C). Substantial authority exists if the weight of authorities supporting a position is substantial compared with the weight of authorities supporting
contrary treatment. Treas. Reg. Section 1.6662-4(d)(3)(i). Relevant authorities include statutes, Regulations, court cases, revenue rulings and procedures, and Congressional intent. However, among other things, conclusions reached in legal opinions
are not considered authority. Treas. Reg. Section 1.6662-4(d)(3)(iii). The Secretary may waive all or a portion of the penalty imposed under Code Section 6662 upon a showing by the taxpayer that there was reasonable cause for the understatement and
that the taxpayer acted in good faith. IRC Section 6664(d). 
  
 Although not anticipated by the General Partner, there may not be substantial authority for one or more reporting positions that the Partnership may take in its federal income tax returns. In such event, if the Partnership does not disclose
or if it fails to adequately disclose any such position, or if such disclosure is deemed adequate but it is determined that there was no reasonable basis for the tax treatment of such a partnership item, the penalty will be imposed with respect to
any substantial understatement determined to have been made, unless the provisions of the Treasury Regulations pertaining to waiver of the penalty become final and the Partnership is able to show reasonable cause and good faith in making the
understatement as specified in such provisions. If the Partnership makes a disclosure for the purposes of avoiding the penalty, the disclosure is likely to result in an audit of such return and a challenge by the Service of such position taken.

  
 If it were determined that a Partner had underpaid tax for any
taxable year, such Partner would have to pay the amount of underpayment plus interest on the underpayment from the date the tax was originally due. The interest rate on underpayments is determined by the Service based upon the federal short term
rate of interest (as defined in Code Section 1274(d)) plus 3%, or 5% for large corporate underpayments, and is compounded daily. The rate of interest is 

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adjusted monthly. In addition, Temporary Regulations provide that tax motivated transactions include, among other items, certain overstatements of the value
of property on a return, losses disallowed by reason of the at-risk limitation any use of an accounting method that may result in a substantial distortion of income for any period, and any deduction disallowed for an activity not entered into for
profit. Although definitive Treasury Regulations have not been promulgated the determination of those transactions to be considered “tax-motivated transactions” is to be made by taking into account the ratio of tax benefits to cash
invested, the method of promoting the transaction, and other relevant transactions. Thus, in the event an audit of the Partnership’s or of a Partner’s tax return results in a substantial underpayment of tax by such Partner due to an
investment in the Units, such Partner may be required to pay interest on such underpayment determined at the higher interest rate. 
  
 A partnership, for federal income tax purposes, is required to file an annual informational tax return. The failure to properly file such a return in a
timely fashion, or the failure to show on such return all information under the Code to be shown on such return, unless such failure is due to reasonable cause, subjects the partnership to civil penalties under the Code in an amount equal to $50 per
month multiplied by the number of partners in the partnership, up to a maximum of $250 per partner per year. In addition, upon any willful failure to file a partnership information return, a fine or other criminal penalty may be imposed on the party
responsible for filing the return. 
  
 ACCOUNTING METHODS AND
PERIODS 
  
 The Partnership will use the accrual method of
accounting and will select the calendar year as its taxable year. 
  
 As discussed above, a taxpayer using the accrual method of accounting will recognize income when all events have occurred which fix the right to receive such income and the amount thereof can be determined with reasonable accuracy.
Deductions will be recognized when all events which establish liability have occurred and the amount thereof can be determined with reasonable accuracy. However, all events which establish liability are not treated as having occurred prior to the
time that economic performance occurs. Code Section 461(h). 
  
 All partnerships are required to conform their tax years to those of their owners; i.e., unless the partnership establishes a business purpose for a different tax year, the tax year of a partnership must be (i) the taxable year of one or
more of its partners who have an aggregate interest in partnership profits and capital of greater than 50%, (ii) if there is no taxable year so described, the taxable year of all partners having interests of 5% or more in partnership profits or
capital, or (iii) if there is no taxable year described in (i) or (ii), the calendar year. Code Section 706. Until the taxable years of the Partners can be identified, no assurance can be given that the Service will permit the Partnership to adopt a
calendar year. 

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 STATE AND LOCAL TAXES 
  
 The opinions expressed herein are limited to issues of federal income tax law and do not address issues of state or local
law. Investors are urged to consult their tax advisors regarding the impact of state and local laws on an investment in the Partnership. 
  
 PROPOSED LEGISLATION AND REGULATIONS 
  
 There can be no assurances that subsequent changes in the tax laws (through new legislation, court decisions, Service pronouncements, Treasury
regulations, or otherwise) will or will not occur that may have an impact, adverse or positive, on the tax effect and consequences of this Transaction, as described above. 
  
 We express no opinion as to any federal income tax issue or other matter except those set forth or confirmed above.

  
 We hereby consent to the filing of this opinion as Exhibit B
to the Memorandum and to all references to our firm in the Memorandum. 
  

	
	 Sincerely,
  

	 Conner & Winters, P.C.

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