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As filed with the Securities and Exchange Commission on January 15, 2008

Registration No. 333-144089



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


AMENDMENT NO. 5
TO
FORM S-1
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933


OGE ENOGEX PARTNERS L.P.
(Exact name of registrant as specified in its charter)


Delaware
(State or jurisdiction of
incorporation or organization)
  4922
(Primary Standard Industrial
Classification Code Number)
  26-0320188
(I.R.S. Employer
Identification No.)

600 Central Park Two, 515 Central Park Drive
Oklahoma City, Oklahoma 73105
(405) 525-7788
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)



Stephen E. Merrill
Vice President and Chief Financial Officer
600 Central Park Two, 515 Central Park Drive
Oklahoma City, Oklahoma 73105
(405) 525-7788
(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:

James R. Hatfield
Senior Vice President and
Chief Financial Officer
OGE Energy Corp.
321 North Harvey
Oklahoma City, Oklahoma 73101-0321
(405) 553-3000

 

Robert J. Joseph
Jones Day
77 West Wacker Drive
Chicago, Illinois 60601
(312) 269-4176

 

Gregory V. Nelson
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002
(713) 229-1645

 

Douglas E. McWilliams
Alan P. Baden
Vinson & Elkins L.L.P.
1001 Fannin Street,
Suite 2500
Houston, Texas 77002
(713) 758-2222

Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.

        If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

        If this Form is filed to register additional securities for an offering pursuant to rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

        The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to Section 8(a), may determine.




Subject To Completion Dated January 15, 2008

The information in this prospectus is not complete and may be changed. We may not offer or sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PROSPECTUS

OGE ENOGEX PARTNERS L.P.
7,500,000 Common Units
Representing Limited Partner Interests

        This is the initial public offering of our common units. All of the common units are being sold by us. We currently estimate that the initial public offering price will be between $18.00 and $20.00 per common unit. Prior to this offering, there has been no public market for our common units. We have applied to list the common units on the New York Stock Exchange under the symbol "OGP." After this offering, we will own a 25% interest in Enogex LLC and OGE Energy Corp. will own the remaining 75% interest.

        Investing in our common units involves risks. Please see "Risk Factors" beginning on page 18.

 
  Per Common Unit
  Total
Initial public offering price   $     $  
Underwriting discount(1)   $     $  
Proceeds, before expenses, to OGE Enogex Partners L.P.   $     $  

(1)
Excludes a structuring fee equal to 0.65% of the gross proceeds of this offering, or approximately $            , payable to UBS Securities LLC.

        We have granted the underwriters a 30-day option to purchase up to an additional 1,125,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 7,500,000 common units in this offering.

        Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

        The underwriters expect to deliver the common units on or about                        , 2008.

UBS Investment Bank Lehman Brothers

Citi   JPMorgan Wachovia Securities

BOSC, Inc.

 

Capital West Securities, Inc.

                                , 2008


OGE ENOGEX PARTNERS L.P.

         GRAPHIC



TABLE OF CONTENTS

SUMMARY   1
  OGE Enogex Partners L.P.   1
  Risk Factors   4
  Formation Transactions and Partnership Structure   4
  Organizational Structure After the Formation Transactions   5
  Management of OGE Enogex Partners L.P.   6
  Summary of Conflicts of Interest and Fiduciary Duties   6
  Principal Executive Offices and Internet Address   7
  The Offering   8
  Summary Historical and Pro Forma Financial and Operating Data   14
  Non-GAAP Financial Measures   16
RISK FACTORS   18
  Risks Related to Our Business   18
  Risks Related to an Investment in Us   36
  Tax Risks to Common Unitholders   46
USE OF PROCEEDS   50
CAPITALIZATION   51
DILUTION   53
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS   55
  General   55
  Our Initial Distribution Rate   56
  Minimum Estimated Adjusted EBITDA for the Year Ending December 31, 2008   59
  Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and the Twelve Months Ended September 30, 2007   63
  Assumptions and Considerations   66
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS   73
  Distributions of Available Cash   73
  Operating Surplus and Capital Surplus   74
  Subordination Period   78
  Distributions of Available Cash from Operating Surplus During the Subordination Period   79
  Distributions of Available Cash from Operating Surplus After the Subordination Period   80
  General Partner Interest and Incentive Distribution Rights   80
  Percentage Allocations of Available Cash from Operating Surplus   81
  General Partner's Right to Reset Incentive Distribution Levels   81
  Distributions from Capital Surplus   84
  Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels   84
  Distributions of Cash Upon Liquidation   85
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA   87
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   91
  Our Business   91
  Operations   91
  Factors That Significantly Affect Our and Enogex's Results   92
  General Trends and Outlook   95
  Factors Affecting Comparability of Future Results   98
  How We Evaluate Our and Enogex's Operations   99
  Results of Operations   100
  Financial Condition   116
  Off-Balance Sheet Arrangements   118
  Liquidity and Capital Resources   118
  Security Ratings   123

i


  Critical Accounting Policies and Estimates   124
  Quantitative and Qualitative Disclosures About Market Risk   127
BUSINESS   132
  Our Partnership   132
  Business Strategies   133
  Competitive Strengths   136
  Our Relationship with OGE Energy   137
  Recent System Expansions   138
  Industry Overview   140
  Our Business   145
  Technology Improvements   152
  Safety and Health Regulation   153
  Environmental Matters   154
  Employees   157
  Properties   157
  Legal Proceedings   158
MANAGEMENT   161
  Management of OGE Enogex Partners L.P.   161
  Governance Matters   161
  Directors and Executive Officers of OGE Enogex GP LLC   162
  Reimbursement of Expenses of Our General Partner   165
  Executive Compensation   166
  Director Compensation   166
  Compensation Discussion and Analysis   166
  Long-Term Incentive Plan   167
  Retention Agreements   169
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT   171
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS   172
  Distributions and Payments to Our General Partner and Its Affiliates   172
  Agreements Governing the Transactions   173
  Omnibus Agreement   173
  Contribution, Conveyance and Assumption Agreement   175
  Enogex LLC Limited Liability Company Agreement   175
  Contracts with Affiliates   175
  Review, Approval or Ratification of Transactions with Related Persons   177
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES   179
  Conflicts of Interest   179
  Fiduciary Duties   185
DESCRIPTION OF THE COMMON UNITS   189
  The Units   189
  Transfer Agent and Registrar   189
  Transfer of Common Units   189
THE PARTNERSHIP AGREEMENT   191
  Organization and Duration   191
  Purpose   191
  Power of Attorney   191
  Cash Distributions   191
  Capital Contributions   192
  Voting Rights   192
  Limited Liability   193
  Issuance of Additional Securities   194
  Amendment to the Partnership Agreement   195
  Merger, Consolidation, Conversion, Sale or Other Disposition of Assets   197

ii


  Termination and Dissolution   198
  Liquidation and Distribution of Proceeds   198
  Withdrawal or Removal of Our General Partner   199
  Transfer of General Partner Interest   200
  Transfer of Membership Interests in Our General Partner   201
  Transfer of Incentive Distribution Rights   201
  Change of Management Provisions   201
  Limited Call Right   201
  Meetings; Voting   202
  Status as Limited Partner   203
  Non-Citizen Assignees; Redemption   203
  Indemnification   203
  Reimbursement of Expenses   203
  Books and Reports   204
  Right to Inspect Our Books and Records   204
  Registration Rights   204
UNITS ELIGIBLE FOR FUTURE SALE   205
MATERIAL TAX CONSEQUENCES   206
  Partnership Status   206
  Limited Partner Status   208
  Tax Consequences of Unit Ownership   208
  Tax Treatment of Operations   214
  Disposition of Common Units   215
  Uniformity of Units   217
  Tax-Exempt Organizations and Non-U.S. Investors   218
  Administrative Matters   218
  State, Local, Foreign and Other Tax Considerations   221
INVESTMENT IN OGE ENOGEX PARTNERS L.P. BY EMPLOYEE BENEFIT PLANS   222
UNDERWRITING   223
  Option to Purchase Additional Common Units   223
  Discounts and Commissions   223
  No Sales of Similar Securities   224
  Indemnification   225
  Directed Unit Program   225
  New York Stock Exchange   225
  Price Stabilization; Short Positions   225
  Determination of Offering Price   226
  Electronic Distribution   226
  Discretionary Sales   226
  Stamp Taxes   227
  Affiliations   227
  FINRA Conduct Rules   227
LEGAL MATTERS   227
EXPERTS   227
WHERE YOU CAN FIND MORE INFORMATION   228
FORWARD-LOOKING STATEMENTS   228
INDEX TO FINANCIAL STATEMENTS   F-1
FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF OGE ENOGEX PARTNERS L.P.   A-1
GLOSSARY OF SELECTED TERMS   B-1

iii



SUMMARY

        This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary may not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the historical and pro forma consolidated financial statements and the notes to those financial statements. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $19.00 per common unit and (2) that the underwriters do not exercise their option to purchase additional common units. You should read "Risk Factors" beginning on page 18 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

        Except as otherwise set forth in the prospectus, all references in this prospectus to our, we, and us refer to OGE Enogex Partners L.P. and its subsidiaries, including its interest in Enogex LLC, after giving effect to the formation transactions described below, including the conversion of Enogex Inc. to Enogex LLC, a Delaware limited liability company. Upon the completion of this offering, a wholly owned subsidiary of OGE Enogex Partners L.P. will own a 25% membership interest in Enogex and serve as its managing member. A wholly owned subsidiary of OGE Energy Corp. will own the remaining 75% membership interest and will be a non-managing member.

        You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.


OGE Enogex Partners L.P.

Our Business

        We are a provider of integrated natural gas midstream services. We were formed by OGE Energy Corp. (NYSE: OGE) to further develop its natural gas midstream assets and operations. OGE Energy is the parent company of Oklahoma Gas and Electric Company, a regulated electric utility, and Enogex Inc., an integrated natural gas midstream services provider. In connection with this offering, Enogex Inc. will convert to Enogex LLC, a Delaware limited liability company. Upon the completion of this offering, a wholly owned subsidiary of OGE Energy will own a 68.2% limited partner interest in us and a 2% general partner interest in us through its ownership of OGE Enogex GP LLC, our general partner. Our wholly owned subsidiary will own a 25% membership interest in Enogex LLC and will be its managing member, and our general partner, on our and our wholly owned subsidiary's behalf, will control the assets and operations of Enogex LLC. A wholly owned subsidiary of OGE Energy will own the remaining 75% membership interest in Enogex LLC and will be a non-managing member.

        Enogex's natural gas gathering, processing, transportation and storage assets are strategically located primarily in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex's transportation pipelines are connected to 11 other major pipelines at approximately 64 pipeline interconnect points providing access to markets in the western United States, the Midwest, Northeast and Gulf Coast in addition to Oklahoma and adjoining states. Through Enogex's gathering and processing assets, Enogex aggregates gas supplies for its markets and also for those markets accessible via its numerous intrastate and interstate pipeline connections.

        Enogex's ongoing operations will be organized into two businesses: (1) natural gas transportation and storage and (2) natural gas gathering and processing.

    Transportation and Storage.  Enogex provides fee-based firm and interruptible intrastate transportation and storage services. Enogex owns and operates approximately 2,283 miles of intrastate natural gas transportation pipelines with approximately 1.52 trillion British thermal

1


      units per day, or TBtu/d, of average daily throughput for the nine months ended September 30, 2007. Enogex owns and operates two natural gas storage facilities with approximately 23 billion cubic feet, or Bcf, of aggregate working gas capacity. For the year ended December 31, 2006 and the nine months ended September 30, 2007, Enogex's transportation and storage business generated approximately $126 million and $108 million, respectively, of its gross margin on revenues, which is revenues minus cost of goods sold and is referred to herein as gross margin.

    Gathering and Processing.  Enogex owns and operates approximately 5,474 miles of natural gas gathering pipelines with approximately 1.04 TBtu/d of average daily throughput for the nine months ended September 30, 2007. Enogex also owns and operates six natural gas processing plants with approximately 720 million cubic feet per day, or MMcf/d, of aggregate inlet capacity and has a 50% ownership interest in and operates an additional natural gas processing plant with approximately 20 MMcf/d of inlet capacity. Enogex provides well connect, gathering, measurement, treating, dehydration, compression and processing services to its producer customers primarily in the Arkoma and Anadarko basins, including those operating in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma. For the year ended December 31, 2006 and the nine months ended September 30, 2007, Enogex's gathering and processing business generated approximately $168 million and $127 million, respectively, of its gross margin.

        Historically, Enogex had also engaged in natural gas marketing through its subsidiary, OGE Energy Resources Inc. In connection with this offering, on January 1, 2008, Enogex distributed the stock of OGE Energy Resources to OGE Energy. Accordingly, immediately following the offering, Enogex's operations will no longer include the marketing of natural gas.

Business Strategies

        Our primary business objective is to increase our cash distributions per unit over time. We intend to accomplish this objective by executing the following business strategies:

    Capturing growth opportunities through expansion projects, increasing utilization of existing assets and strategic acquisitions.  

    Maintaining strong customer relationships based upon high quality service, reliability and efficiency of Enogex's existing assets and operations.  

    Maintaining sound financial practices.  

Competitive Strengths

        We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:

    Enogex's assets are strategically located.

    Enogex has transportation and processing flexibility.

    We have a management team and board of directors with significant experience in the natural gas midstream industry.

    Enogex has operated for more than 50 years in the natural gas midstream industry.

    We have the financial flexibility to pursue growth opportunities.

    We focus on operational efficiencies in our business.

2


Our Relationship with OGE Energy

        One of our principal strengths is our relationship with OGE Energy. Since its inception, Enogex has been the transporter of natural gas to Oklahoma Gas and Electric Company's natural gas-fired electric generation facilities. Enogex's current contract with Oklahoma Gas and Electric Company provides for no-notice load following transportation and storage services. For the years ended December 31, 2004, 2005 and 2006 and the nine months ended September 30, 2007, revenues attributed to Oklahoma Gas and Electric Company were approximately $49.6 million, $47.6 million, $47.6 million and $35.5 million, respectively, under the contract. We believe Enogex also benefits from a higher credit rating due to its relationship with OGE Energy.

        As indicated above, in connection with this offering, Enogex distributed the stock of OGE Energy Resources to OGE Energy. Enogex has historically utilized, and is expected to continue to utilize, OGE Energy Resources for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2004, 2005 and 2006 and the nine months ended September 30, 2007, OGE Energy Resources recorded revenues from Enogex of approximately $98.3 million, $160.6 million, $107.1 million and $71.9 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2004, 2005 and 2006 and the nine months ended September 30, 2007, Enogex recorded revenues from OGE Energy Resources of approximately $299.5 million, $330.5 million, $291.9 million and $222.9 million, respectively, for the sale, at market rates, of natural gas. Enogex has paid, and is expected to continue to pay, certain fees for providing natural gas marketing, hedging, risk management and other related services to OGE Energy Resources as described in more detail in "Certain Relationships and Related Party Transactions—Contracts with Affiliates—Marketing and Administrative Services Agreement with OERI."

        OGE Energy has indicated that it intends to use our partnership to manage and further develop its natural gas midstream assets. In addition, OGE Energy has indicated that it intends to offer us the opportunity to purchase all of the remaining ownership interests in Enogex in the future, although OGE Energy is not obligated to do so. While we believe that it will be in OGE Energy's best interest to sell the remaining ownership interest in Enogex to us given its significant ownership interest in us, OGE Energy may elect to acquire, construct or dispose of midstream assets, including its interest in Enogex, in the future without offering us the opportunity to purchase or construct those assets. We cannot say with any certainty that we will have the opportunity to acquire the remaining ownership interests in Enogex.

        Through our relationship with OGE Energy, we expect to have access to a significant pool of management talent and access to OGE Energy's broad technical, risk management and administrative infrastructure. Please see "Certain Relationships and Related Party Transactions—Omnibus Agreement."

Recent System Expansions

        Over the past several years, Enogex has executed on multiple organic growth projects. Currently, Enogex's organic growth capital expenditures are focused on three primary areas:

    upgrades to Enogex's existing transportation system due to increased volumes as a result of the broader shift of gas flow from the Rocky Mountains and the mid-continent to markets in the northeast and southeast United States;

    expansions on the east side of Enogex's gathering system, primarily in the Woodford Shale play in southeastern Oklahoma; and

    expansions on the west side of Enogex's gathering system, primarily in the Granite Wash play in the Wheeler County, Texas area, which is located in the Texas Panhandle.

        Please see "Business—Recent System Expansions."

3



Risk Factors

        An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please see the risks described under "Risk Factors."


Formation Transactions and Partnership Structure

Formation Transactions

        In connection with this offering, on January 1, 2008, Enogex Inc., which is currently an Oklahoma corporation, distributed the shares of its subsidiary, OGE Energy Resources, to OGE Energy and expects to enter into an agreement with OGE Energy Resources for natural gas marketing, hedging, risk management and other related services.

        Prior to the closing of this offering, Enogex Inc. will reincorporate under the laws of the State of Delaware and convert to Enogex LLC, a Delaware limited liability company. In addition, a wholly owned subsidiary of Enogex, Enogex Products Corporation, will convert from an Oklahoma corporation to an Oklahoma limited liability company.

        At the closing of this offering, the following transactions will occur:

    OGE Energy will contribute to our wholly owned subsidiary a membership interest in Enogex;

    we will issue to OGE Enogex Holdings LLC, a wholly owned subsidiary of OGE Energy, 4,829,214 common units and 12,329,214 subordinated units, collectively representing a 68.2% limited partner interest in us;

    we will issue to OGE Enogex GP LLC, our general partner and a subsidiary of OGE Energy, a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;

    we will enter into an omnibus agreement with our general partner and OGE Energy and certain of its affiliates which will address, among other things, our and Enogex's reimbursement of expenses to OGE Energy for the payment of certain operating expenses and the provision of various general and administrative services in connection with this offering and the indemnification of us and Enogex by OGE Energy for certain matters;

    we will issue 7,500,000 common units to the public in this offering, representing a 29.8% limited partner interest in us, and will use the proceeds as described under the caption "Use of Proceeds"; and

    we will contribute approximately $130.2 million to Enogex in exchange for an additional membership interest in Enogex, bringing our total interest in Enogex to 25% following the closing of this offering.

        At the closing of this offering, Enogex expects to enter into a $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes and to borrow approximately $13.9 million under this facility. Enogex also currently expects to redeem its $400 million 8.125% senior notes due 2010, and pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million, with a combination of approximately $300 million of short-term borrowings from OGE Energy, approximately $11.3 million of the $13.9 million of initial borrowings under its new credit facility and the approximately $130.2 million of net proceeds of this offering that we expect to contribute to Enogex for the anticipated repayment of that debt. Enogex expects to repay the amounts borrowed from OGE Energy for the redemption of its $400 million 8.125% senior notes due 2010 with the proceeds of an issuance of up to $300 million of new long-term debt.

4



Organizational Structure After the Formation Transactions

        As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through our subsidiaries. We will initially have one direct subsidiary, Enogex Operating LLC, a limited liability company, that will conduct business through its subsidiaries. Enogex Operating LLC will hold our 25% interest in Enogex.

        The following diagram depicts our organization and ownership after giving effect to the offering and the related formation transactions described above.

Public Common Units   29.8 %
Affiliate of OGE Energy Corp. Common Units   19.2 %
Affiliate of OGE Energy Corp. Subordinated Units   49.0 %
General Partner Interest   2.0 %
   
 
  Total   100.0 %

GRAPHIC


(1)
Assumes the underwriters do not exercise their option to purchase additional common units. If the underwriters exercise in full their option to purchase additional common units, we intend to contribute the additional net proceeds to Enogex, which would increase our interest in Enogex to approximately 26% and decrease OGE Energy's interest in Enogex to approximately 74%.

5



Management of OGE Enogex Partners L.P.

        OGE Enogex GP LLC, our general partner, will manage our business and operations. The board of directors and executive officers of our general partner will oversee our operations and make decisions on our behalf. Some of the executive officers and directors of OGE Energy also serve as executive officers or directors of our general partner.

        Unlike shareholders in a publicly traded corporation, our common unitholders will not be entitled to elect our general partner or its directors. OGE Energy will elect all seven members to the board of directors of our general partner, and our general partner will have four directors who are independent as defined under the independence standards established by the New York Stock Exchange. For more information about our management, please see "Management—Directors and Executive Officers of OGE Enogex GP LLC."


Summary of Conflicts of Interest and Fiduciary Duties

General

        OGE Enogex GP LLC, our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a "fiduciary duty." However, because our general partner is indirectly owned by OGE Energy, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to OGE Energy. Our general partner, on our behalf as Enogex's managing member, will control Enogex's business and operations. Accordingly, our general partner will have a fiduciary duty to manage Enogex in a manner beneficial to us as well as to Enogex's non-managing member.

        The board of directors of our general partner may resolve any conflict between the interests of us and our unitholders, on the one hand, and OGE Energy and its affiliates, on the other hand, and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders.

        As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including OGE Energy and Enogex, on the other hand. For example, our general partner will be entitled to make determinations that affect our ability to make cash distributions to the holders of common units which in turn will have an effect on whether our general partner receives incentive cash distributions as discussed below.

        For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, including the types of determinations our general partner will be entitled to make, please see "Conflicts of Interest and Fiduciary Duties."

Partnership Agreement Modifications to Fiduciary Duties

        Our partnership agreement limits our general partner's fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties owed to our unitholders. Our partnership agreement also provides that OGE Energy and its affiliates (other than our general partner) are not limited in their ability to compete with us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

6


        For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please see "Conflicts of Interest and Fiduciary Duties."


Principal Executive Offices and Internet Address

        Our principal executive offices are located at 600 Central Park Two, 515 Central Park Drive, Oklahoma City, Oklahoma 73105, and our telephone number is (405) 525-7788. Upon completion of this offering, our website will be located at http://www.enogexpartners.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, on our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

7



The Offering

Common units offered to the public   7,500,000 common units or 8,625,000 common units if the underwriters exercise in full their option to purchase additional common units.

Units outstanding after this offering

 

12,329,214 common units and 12,329,214 subordinated units, representing 49.0% and 49.0%, respectively, limited partner interests in us (13,454,214 common units and 12,329,214 subordinated units, representing 51.1% and 46.9%, respectively, limited partner interests in us if the underwriters exercise in full their option to purchase additional common units).

Use of proceeds

 

We expect to receive net proceeds from this offering of approximately $132.7 million, after deducting underwriting discounts and commissions and a structuring fee. We base this amount on an assumed initial public offering price of $19.00 per common unit and assuming no exercise of the underwriters' option to purchase additional common units. We anticipate using the net proceeds of this offering to pay approximately $2.5 million of expenses associated with the offering and related formation transactions and contributing the remaining net proceeds to Enogex.

 

 

Enogex anticipates using those proceeds, together with approximately $300 million of short-term borrowings from OGE Energy, approximately $13.9 million of borrowings under its new credit facility and approximately $1.9 million of cash on hand, to:

 

 


redeem its $400 million 8.125% senior notes due 2010, including payment of approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million; and

 

 


pay approximately $4.5 million in fees and expenses related to Enogex's new credit facility and an issuance of up to $300 million of new long-term debt, the proceeds of which will be used to repay the short-term borrowings from OGE Energy.

8



 

 

If the underwriters' option to purchase additional common units is exercised, we intend to contribute the additional net proceeds to Enogex to pay a portion of the make-whole premium and of the fees described above, or repay short-term borrowings incurred to pay such premium and fees, and to use the balance to fund future capital expenditures and working capital and for other corporate purposes. Because the contribution of those additional net proceeds would be considered a capital contribution from us to Enogex, our interest in Enogex following that contribution would increase to approximately 26% and OGE Energy's interest in Enogex would decrease to approximately 74%.

Cash distributions

 

We will make an initial quarterly distribution of $0.3375 per common unit ($1.35 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption "Cash Distribution Policy and Restrictions on Distributions."

 

 

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as "available cash," and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B. Our partnership agreement requires that we distribute all of our available cash from operating surplus each quarter in the following manner:

 

 


first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.3375 plus any arrearages from prior quarters;

 

 


second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.3375; and

 

 


third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a total distribution of $0.3881.

9



 

 

If cash distributions to our unitholders exceed $0.3881 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions."

 

 

Assuming the underwriters exercise their option to purchase additional common units, the amount of our estimated pro forma cash available for distribution generated during the year ended December 31, 2006 and the twelve months ended September 30, 2007 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only 91.6% and 80.7%, respectively, of the minimum quarterly distribution on our subordinated units during those periods. Please see "Cash Distribution Policy and Restrictions on Distributions."

 

 

We believe that, based on the Statement of Minimum Estimated Adjusted EBITDA for the Year Ending December 31, 2008 included under the caption "Cash Distribution Policy and Restrictions on Distributions," we will have sufficient cash available for distribution to make cash distributions for the four quarters ending December 31, 2008 at the initial distribution rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis) on all common units and subordinated units.

Subordinated units

 

OGE Energy, through a wholly owned subsidiary, will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.3375 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Subordination period

 

The subordination period will end on the first business day after we have earned and paid at least $1.35 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and made the corresponding distribution on the 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010.

10



 

 

Alternatively, the subordination period will end on the first business day after we have earned and paid at least $0.50625 (150% of the minimum quarterly distribution) on each outstanding limited partner unit and made the corresponding distribution on the 2% general partner interest for each quarter for four consecutive quarters.

 

 

In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

 

 

When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

General partner's right to reset the target distribution levels

 

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset election, referred to herein as the "reset minimum quarterly distribution," and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

11



 

 

In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible at any time into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. For a more detailed description of our general partner's right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Issuance of additional units

 

We can issue an unlimited number of units without the consent of our unitholders. Please see "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Securities."

Limited voting rights

 

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, limited partners will have only limited voting rights on matters affecting our business. Limited partners will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, an affiliate of our general partner will own an aggregate of 69.6% of our common and subordinated units. This will give our general partner the ability to prevent its involuntary removal. Please see "The Partnership Agreement—Voting Rights."

Limited call right

 

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.

12



Estimated ratio of taxable income to distributions

 

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.35 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.27 per unit. Please see "Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions."

Material tax consequences

 

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please see "Material Tax Consequences."

Exchange listing

 

We have applied to list the common units on the New York Stock Exchange under the symbol "OGP."

13



Summary Historical and Pro Forma Financial and Operating Data

        OGE Enogex Partners L.P. was formed on May 30, 2007 and does not have any historical financial statements prior to its formation. The following tables set forth, for the periods and at the dates indicated, the summary historical financial and operating data of Enogex Inc. and its subsidiaries, or Enogex Predecessor, which financial data is derived from the books and records of Enogex Predecessor, and the summary pro forma financial and operating data of OGE Enogex Partners L.P.

        The summary historical financial data for the years ended December 31, 2006, 2005 and 2004 and balance sheet data at December 31, 2006 and 2005 is derived from and should be read in conjunction with the audited historical consolidated financial statements of Enogex Predecessor included elsewhere in this prospectus beginning on page F-12. The summary historical balance sheet data at December 31, 2004 is derived from the audited historical consolidated financial statements of Enogex Predecessor. The summary historical financial data for the nine months ended September 30, 2007 and 2006 and at September 30, 2007 is derived from and should be read in conjunction with the unaudited historical condensed consolidated financial statements of Enogex Predecessor included elsewhere in this prospectus beginning on page F-62. In each case, the summary historical financial and operating data reflects 100% of Enogex's operations, but following our formation transactions (and as reflected in the pro forma financial data), we will own only a 25% interest in Enogex. Also, in each case, the summary historical financial and operating data reflects Enogex's ownership of OGE Energy Resources, but following our formation transactions (and as reflected in the pro forma financial and operating data), Enogex will not own OGE Energy Resources. OGE Energy Resources' results of operations are included in the summary historical financial and operating data as, subsequent to the distribution of the stock of OGE Energy Resources to OGE Energy, it is anticipated that the ongoing transactions between OGE Energy Resources and Enogex will constitute a significant continuation of activities and cash flows for Enogex. The operating data for all periods is unaudited. The summary pro forma financial data is derived from and should be read in conjunction with the unaudited pro forma consolidated financial statements of OGE Enogex Partners L.P. included in this prospectus beginning on page F-2. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the balance sheet data, and as of January 1, 2006 in the case of the statements of income for the year ended December 31, 2006 and the nine months ended September 30, 2007. These transactions include:

    the distribution by Enogex of the shares of OGE Energy Resources to OGE Energy;

    the dividend by Enogex of outstanding advances to OGE Energy Resources to OGE Energy;

    the conversion of Enogex Inc. to a Delaware limited liability company;

    the conversion of outstanding intercompany loans from Enogex to OGE Energy to a dividend from Enogex to OGE Energy;

    our ownership of a 25% membership interest in Enogex;

    the issuance by us of common units to the public;

    the payment of underwriting discounts and commissions, the structuring fee and other offering expenses;

    the contribution by us of proceeds of this offering to Enogex;

    the redemption by Enogex of its $400 million 8.125% senior notes due 2010; and

    interest expense associated with short-term borrowings from OGE Energy incurred to pay a portion of the costs associated with the expected redemption of Enogex's $400 million 8.125% senior notes due 2010 and associated with borrowings under Enogex's new credit facility.

14


        The following tables include the financial measure of Adjusted EBITDA, which is calculated and presented not in accordance with generally accepted accounting principles in the United States, or GAAP. We define Adjusted EBITDA as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see "—Non-GAAP Financial Measures."

        The following table presents the summary historical financial and operating data of Enogex Predecessor and our summary pro forma financial and operating data for the periods indicated:

 
  Enogex Predecessor
  OGE Enogex Partners L.P.
 
 
  Year Ended December 31,
  Nine Months Ended September 30,
  Year Ended December 31, 2006
  Nine Months Ended September 30, 2007
 
 
  2004
  2005
  2006
  2006
  2007
  Pro Forma(1)
  Pro Forma(1)
 
 
  (in millions, except per unit and operating data)

 
Results of Operations Data:                                            
  Operating revenues   $ 3,372.2   $ 4,340.1   $ 2,367.8   $ 1,838.0   $ 1,509.3   $ 832.9   $ 659.0  
  Cost of goods sold     3,118.2     4,090.4     2,060.4     1,616.4     1,255.8     539.6     424.2  
   
 
 
 
 
 
 
 
  Gross margin on revenues     254.0     249.7     307.4     221.6     253.5     293.3     234.8  
  Other operation and maintenance(2)     93.5     96.6     110.0     80.3     88.4     103.0     85.8  
  Depreciation     41.1     40.4     42.3     31.2     33.9     42.1     33.8  
  Impairment of assets     7.8         0.3     0.3     0.5     0.3     0.5  
  Taxes other than income     16.0     15.4     16.0     12.6     12.0     15.5     11.5  
   
 
 
 
 
 
 
 
  Operating income     95.6     97.3     138.8     97.2     118.7     132.4     103.2  
  Interest income     3.2     2.9     11.1     8.7     7.0     2.9     0.2  
  Other income     4.5     0.8     7.7     6.4     0.8     7.7     0.7  
  Other expense     0.3     0.3     0.3     0.2     0.2     0.3     0.2  
  Interest expense(3)     32.2     32.6     31.8     23.8     24.2     24.6     18.6  
  Income tax expense     26.4     23.4     48.0     33.9     39.3          
   
 
 
 
 
 
 
 
  Income from continuing operations     44.4     44.7     77.5     54.4     62.8     118.1     85.3  
  Income from discontinued operations     11.6     49.8     36.0     36.0              
   
 
 
 
 
 
 
 
  Income before non-controlling interest     56.0     94.5     113.5     90.4     62.8     118.1     85.3  
  Non-controlling interest(4)                         (89.5 )   (64.7 )
   
 
 
 
 
 
 
 
  Net income   $ 56.0   $ 94.5   $ 113.5   $ 90.4   $ 62.8   $ 28.6   $ 20.6  
   
 
 
 
 
 
 
 
  General partner's interest in net income                                 $ 0.6   $ 0.4  
                                 
 
 
  Limited partners' interest in net income                                 $ 28.0   $ 20.2  
                                 
 
 
  Number of outstanding common units                                   12.3     12.3  
  Number of outstanding subordinated units                                   12.3     12.3  
  Basic and diluted earnings per common unit                                 $ 1.14   $ 0.82  
  Basic and diluted earnings per subordinated unit                                 $ 1.14   $ 0.82  

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Property, plant and equipment, net(5)   $ 1,016.5   $ 875.9   $ 865.7   $ 859.9   $ 927.0         $ 926.5  
  Total assets     1,719.7     1,652.6     1,319.8     1,336.0     1,237.8           1,024.0  
  Long-term debt     477.8     407.6     403.7     404.0     402.0           313.9  
  Net owner equity     491.0     440.4     400.0     399.7     380.3           181.9  

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net cash flows provided by (used in):                                            
    Operating activities   $ 118.2   $ 235.2   $ 131.6   $ 73.8   $ 69.0              
    Investing activities     (22.5 )   (34.5 )   (65.1 )   (49.1 )   (96.3 )            
    Financing activities     (118.6 )   (304.0 )   (139.4 )   (20.9 )   29.2              
  Adjusted EBITDA     140.9     138.2     188.5     134.6     153.2   $ 181.9   $ 137.5  

15


Operating Data (excludes discontinued operations):                                            
  New well connects(6)             362     276     295     362     295  
  New well connects(7)     192     223     206     154     137     206     137  
  Gathered volumes—TBtu/d     0.84     0.92     0.98     0.97     1.04     0.98     1.04  
  Incremental transportation volumes—TBtu/d(8)     0.39     0.39     0.46     0.48     0.48     0.46     0.48  
  Total throughput volumes—
TBtu/d
    1.23     1.31     1.44     1.45     1.52     1.44     1.52  
  Natural gas processed—TBtu/d     0.50     0.52     0.54     0.53     0.56     0.54     0.56  
  Natural gas liquids sold (keep-whole)—million gallons     185     191     244     181     178     244     178  
  Natural gas liquids sold (purchased for resale)—million gallons     78     96     113     76     83     113     83  
  Natural gas liquids sold (percent-of- liquids)—million gallons     16     15     14     10     12     14     12  
  Total natural gas liquids sold—million gallons     279     302     371     267     273     371     273  
  Average sales price per gallon   $ 0.720   $ 0.873   $ 0.901   $ 0.914   $ 0.982   $ 0.901   $ 0.982  

(1)
The pro forma data for the year ended December 31, 2006 and the nine months ended September 30, 2007 reflects the distribution of the stock of OGE Energy Resources to OGE Energy.

(2)
The pro forma financial data for the year ended December 31, 2006 and the nine months ended September 30, 2007 include expenses of the partnership incurred as a result of being a publicly traded partnership of $1.1 million and $1.1 million, respectively. These partnership expenses are not expenses of Enogex and, therefore, are added back to income before non-controlling interest prior to calculating the non-controlling interest.

(3)
Under the provisions of Enogex's $400 million 8.125% senior notes due 2010 currently expected to be redeemed in connection with this offering, Enogex will pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million in connection with that redemption. As these items do not have a continuing impact, no adjustments for these items are provided in the accompanying unaudited pro forma consolidated statements of income.

(4)
Represents OGE Energy's 75% ownership interest in Enogex.

(5)
Includes net property, plant and equipment related to discontinued operations of approximately $169.3 million and $34.9 million during 2004 and 2005, respectively.

(6)
Includes wells behind central receipt points (as reported to us by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site. This information is not available for years prior to 2006 as Enogex Predecessor's books and records were not maintained in a manner to provide this information for years prior to 2006.

(7)
Excludes wells behind central receipt points. A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site.

(8)
Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.


Non-GAAP Financial Measures

        We include in this prospectus the non-GAAP financial measure Adjusted EBITDA. We provide reconciliation of Adjusted EBITDA to its most directly comparable financial measures as calculated and presented in accordance with GAAP.

        We define Adjusted EBITDA as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. Adjusted EBITDA is used as a supplemental financial

16



measure by external users of our financial statements such as investors, commercial banks and others, to assess:

    the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis;

    Enogex's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

    the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

        The economic substance behind the use of Adjusted EBITDA is to measure the ability of Enogex's assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to its members.

        The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income from continuing operations. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income from continuing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

        To compensate for the limitations of Adjusted EBITDA as an analytical tool, we believe it is important to review the comparable GAAP measures and understand the differences between the measures.

 
  Enogex Predecessor
  OGE Enogex Partners L.P.
 
 
  Year Ended December 31,
  Nine Months Ended September 30,
  Year Ended December 31, 2006
  Nine Months Ended September 30, 2007
 
 
  2004
  2005
  2006
  2006
  2007
  Pro Forma
  Pro Forma
 
 
  (in millions)

 
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:                                            
  Net cash provided by operating activities   $ 118.2   $ 235.2   $ 131.6   $ 73.8   $ 69.0   $ 103.5   $ 50.5  
  Interest expense, net     29.0     29.7     20.7     15.1     17.2     21.7     18.4  
  Changes in operating working capital which provided (used) cash:                                            
    Accounts receivable     169.4     60.3     (236.9 )   (279.7 )   (73.3 )   (26.8 )   (54.5 )
    Accounts payable     (151.2 )   (84.6 )   222.7     275.7     79.8     8.4     (6.3 )
    Other, including changes in noncurrent assets and liabilities     (24.5 )   (102.4 )   50.4     49.7     60.5     75.1     129.4  
   
 
 
 
 
 
 
 
  Adjusted EBITDA   $ 140.9   $ 138.2   $ 188.5   $ 134.6   $ 153.2   $ 181.9   $ 137.5  
   
 
 
 
 
 
 
 

Reconciliation of Adjusted EBITDA to net income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Net income   $ 56.0   $ 94.5   $ 113.5   $ 90.4   $ 62.8   $ 28.6   $ 20.6  
    Add:                                            
    Interest expense, net     29.0     29.7     20.7     15.1     17.2     21.7     18.4  
    Income tax expense     26.4     23.4     48.0     33.9     39.3          
    Depreciation     41.1     40.4     42.3     31.2     33.9     42.1     33.8  
  Discontinued operations, net income     (11.6 )   (49.8 )   (36.0 )   (36.0 )            
  Non-controlling interest                         89.5     64.7  
   
 
 
 
 
 
 
 
  Adjusted EBITDA   $ 140.9   $ 138.2   $ 188.5   $ 134.6   $ 153.2   $ 181.9   $ 137.5  
   
 
 
 
 
 
 
 

17



RISK FACTORS

        Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

    Because our interest in Enogex currently represents our only cash-generating asset, our cash flows initially will depend completely on Enogex's ability to make distributions to its members, including us. Enogex's ability to make distributions depends on a number of factors, some of which are beyond our and Enogex's control.

        Our cash flows initially will depend completely on Enogex's distributions to us as one of its members. The amount of cash Enogex can distribute to its members will principally depend upon the amount of cash it generates from its operations, which may fluctuate from quarter to quarter based on, among other things:

    the fees Enogex charges and the margins Enogex realizes for its services;

    the prices of, levels of production of, and demand for natural gas;

    the volume of natural gas Enogex purchases, gathers, treats, compresses, processes, transports, stores and sells;

    the relationship between prices for natural gas and natural gas liquids, or NGLs;

    cash calls and settlements of hedging positions;

    margin requirements on open price risk management assets and liabilities;

    the level of competition from other midstream energy companies;

    the level of Enogex's other operation and maintenance expenses and general and administrative costs; and

    prevailing economic conditions.

        In addition, the actual amount of cash Enogex will have available for distribution to its members, including us, will depend on other factors, including:

    the level of capital expenditures it makes;

    its ability to make borrowings under its credit facility to pay distributions;

    the cost of acquisitions;

    its debt service requirements and other liabilities;

    fluctuations in its working capital needs;

    Enogex's ability to borrow funds and access capital markets;

    restrictions contained in Enogex's debt agreements; and

    the amount of Enogex's cash reserves established to fund its operations.

18


        Some of these factors are beyond our and Enogex's control. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see "Cash Distribution Policy and Restrictions on Distributions."

        Enogex's limited liability company agreement provides that it will distribute its available cash to its members on at least a quarterly basis. Enogex's available cash includes cash on hand less any reserves that may be appropriate for operating its business. The amount of Enogex's distributions, including the amount of cash reserves not distributed, will be determined by the board of directors of our general partner.

    We may not have sufficient cash from operations to enable us to make cash distributions to our unitholders at the initial distribution rate under our cash distribution policy or to increase distributions.

        Our ability to distribute to our unitholders any cash we may receive from Enogex or any future operating subsidiaries is or may be limited by a number of factors, including, among others:

    our debt service requirements and other liabilities;

    our ability to make borrowings under our debt agreements to pay distributions;

    restrictions on distributions contained in any of our debt agreements;

    fees and expenses of our general partner and its affiliates we are required to reimburse; and

    the amount of cash reserves established by our general partner.

        Many of these factors will reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we do make may not be at or above our minimum quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on several factors, many of which are beyond the control of us or our general partner.

        For a calculation of our ability to make distributions to unitholders based on our pro forma results, please see "Cash Distribution Policy and Restrictions on Distributions."

    On a pro forma basis, we would not have had sufficient cash available for distribution to pay the minimum quarterly distribution on all units for the year ended December 31, 2006 and the twelve months ended September 30, 2007.

        The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our common units and subordinated units to be outstanding immediately after this offering and the corresponding distribution on the 2% general partner interest is approximately $34.0 million (approximately $35.5 million if the underwriters exercise in full their option to purchase additional common units). On a pro forma basis, the amount of our cash available for distribution generated during the year ended December 31, 2006 and the twelve months ended September 30, 2007 would have been sufficient to make aggregate cash distributions equal to 100% of the minimum quarterly distribution on our common units but only 92.8% and 82.5%, respectively, of the minimum quarterly distribution on our subordinated units (91.6% and 80.7%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of an estimate of our ability to make distributions to unitholders based on our pro forma results for the year ended December 31, 2006 and the twelve months ended September 30, 2007, please read "Cash Distribution Policy and Restrictions on Distributions."

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    The amount of cash we have available for distribution to our unitholders depends primarily on our and Enogex's cash flows and not solely on profitability.

        The amount of cash we have available for distribution depends primarily upon our and Enogex's cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

    The assumptions underlying our estimate of cash available for distribution included under the caption "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        Our estimate of cash available for distribution set forth in "Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the year ending December 31, 2008. Our estimate and related assumptions have been prepared by, and are the responsibility of, management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

    Natural gas and NGL prices are volatile, and changes in these prices could adversely affect our and Enogex's revenue and cash available for distribution.

        Enogex is subject to risks due to frequent and often substantial fluctuations in commodity prices. Our and Enogex's results of operations and cash available for distribution could be adversely affected by volatility in natural gas and NGL prices. Our gathering and processing margins generally improve when NGL prices are high relative to the price of natural gas. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. With respect to natural gas, the mid-continent prices for natural gas, as represented by the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract in 2006 ranged from a high of $8.76 per million British thermal unit, or MMBtu, to a low of $3.54 per MMBtu. In 2007, the same index ranged from a high of $6.82 per MMBtu to a low of $4.73 per MMBtu. Natural gas prices reached relatively high levels in late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. With respect to NGLs, the mid-continent prices for propane, for example, as represented by the average of the Oil Price Information Service daily average posting at the Conway, Kansas market, in 2006 ranged from a high of $1.14 per gallon to a low of $0.90 per gallon. In 2007, the same index ranged from a high of $1.52 per gallon to a low of $0.87 per gallon.

        Our and Enogex's future revenue and cash flows may be materially adversely affected if the midstream industry experiences significant, prolonged deterioration below general price levels experienced in recent years.

    Some factors that affect prices of natural gas and NGLs are beyond our control and changes in these prices could adversely affect our and Enogex's revenue and cash available for distribution.

        The markets and prices for natural gas and NGLs depend upon factors beyond our and Enogex's control and changes in these prices could adversely affect our and Enogex's revenue and cash available for distribution. These factors include demand for these commodities, which fluctuates with changes in

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market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquified natural gas and NGLs, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.

    Enogex's "keep-whole" natural gas processing arrangements and "percent-of-proceeds" and "percent-of-liquids" natural gas processing agreements expose it to risks associated with fluctuations associated with the price of natural gas and NGLs, which could adversely affect our and Enogex's revenue and cash available for distribution.

        Enogex's keep-whole natural gas processing arrangements, which constituted approximately 18% of its gross margin and accounted for approximately 69% of its natural gas processed volumes during the first nine months of 2007 and approximately 23% of its gross margin and approximately 73% of its natural gas processed volumes in 2006, expose it to fluctuations in the pricing spreads between NGL prices and natural gas prices. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a Btu basis by replacing the Btu's of the NGLs extracted from the production stream with Btu's of natural gas. Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu's of natural gas at higher prices and processing margins are negatively affected. For information regarding Enogex's hedging activities, please see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk—Non-Trading Activities."

        Enogex's percent-of-proceeds and percent-of-liquids natural gas processing agreements constituted approximately 6% of its gross margin and accounted for approximately 24% of its natural gas processed volumes during the first nine months of 2007 and approximately 4% of its gross margin and approximately 19% of its natural gas processed volumes in 2006. Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which Enogex shares in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which Enogex receives proceeds from the sale of NGLs or the NGLs themselves as compensation for its processing services as percent-of-liquids arrangements. These arrangements expose Enogex to risks associated with the price of natural gas and NGLs.

        At any given time, Enogex's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that Enogex was a net buyer of natural gas) and a net long position in NGLs (meaning that Enogex was a net seller of NGLs). As a result, Enogex's margins could be negatively impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

    Because of the natural decline in production from existing wells connected to Enogex's systems, Enogex's success depends on its ability to gather new sources of natural gas, which depends on certain factors beyond its or our control. Any decrease in supplies of natural gas could adversely affect our and Enogex's business and results of operations and cash available for distribution.

        Enogex's gathering and transportation systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, Enogex's cash flows associated with these wells will also decline over time. To maintain or increase

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throughput levels on its gathering and transportation systems and the asset utilization rates at its natural gas processing plants, Enogex must continually obtain new natural gas supplies. The primary factors affecting Enogex's ability to obtain new supplies of natural gas and attract new customers to its assets depends in part on the level of successful drilling activity near these systems, Enogex's ability to compete for volumes from successful new wells and Enogex's ability to expand capacity as needed.

        If Enogex is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on its gathering, processing and transportation facilities would decline, which could have a material adverse effect on our and its business, results of operations and cash available for distribution.

    Our and Enogex's ability to make cash distributions will depend, in part, on the drilling decisions of others.

        All of Enogex's businesses and ultimately our and its ability to make cash distributions are dependent on the continued availability of natural gas production. Neither we nor Enogex have control over the level of drilling activity in the areas of Enogex's operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. The primary factor that impacts drilling decisions is natural gas prices. Natural gas prices reached relatively high levels in late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by Enogex's gathering, processing and transportation facilities, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers' capital budgets, the ability of producers to obtain necessary drilling and other governmental permits, costs of steel and other commodities, geological considerations, demand for hydrocarbons, the level of reserves, other production and development costs and regulatory changes.

        Because of these factors, even if new natural gas reserves are discovered in areas served by Enogex's assets, producers may choose not to develop those reserves.

    Enogex engages in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on its earnings and cash flows and its ability to make distributions to its members, including us.

        Enogex is exposed to changes in commodity prices in its operations. To minimize the risk of commodity prices, Enogex may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas. However, financial derivative contracts do not eliminate the risk of market supply shortages, which could result in Enogex's inability to fulfill contractual obligations and incurrence of significantly higher energy or fuel costs relative to corresponding sales contracts.

        Enogex marks its energy trading portfolio to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. When available, market prices are utilized in determining the value of natural gas and related derivative commodity instruments. For longer-term positions, which are limited to a maximum of 60 months, and certain short-term positions for which market prices are not available, models based on forward price curves are utilized. These models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

        Enogex engages in cash flow hedge transactions to manage commodity risk. Hedges of anticipated transactions are documented as cash flow hedges pursuant to Statement of Financial Accounting Standard, or SFAS, No. 133, "Accounting for Derivative Instruments and Hedging Activities," and are executed based upon management-established price targets. Enogex utilizes hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and storage natural gas,

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percent-of-liquids and keep-whole natural gas, natural gas liquid hedges and certain transportation hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative's change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

        As a result of the factors discussed above, Enogex's hedging activities may not be as effective as intended in reducing the volatility of its cash flows, which could adversely affect its ability to make distributions to its members, including us. In addition, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective or the hedging policies and procedures are not properly followed or do not work as planned. The steps taken to monitor Enogex's hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. For additional information regarding Enogex's hedging activities, please see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk."

    Enogex's results of operations and cash flows may be adversely affected by risks associated with its hedging activities.

        Enogex has instituted a hedging program that is intended to reduce the commodity price risk associated with Enogex's keep-whole and percent-of-liquids arrangements. Enogex intends to hedge approximately 70% of its NGL volumes when market conditions dictate. As of December 31, 2007, Enogex had hedged approximately 63% of its expected non-ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008, 2009 and 2010. As of December 31, 2007, Enogex had hedged approximately 41% of its expected ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008. Enogex has the option to reject ethane if processing it is not economical.

        For periods after 2010, management will evaluate whether to enter into any new hedging arrangements, and there can be no assurance that Enogex will enter into any new hedging arrangements. Also, Enogex may seek in the future to further limit its exposure to changes in natural gas and NGL commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms. To the extent Enogex hedges its commodity price and interest rate exposures, we and Enogex will forego the benefits that otherwise would be experienced if commodity prices or interest rates were to change in Enogex's favor. In addition, even though management monitors Enogex's hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or the hedging policies and procedures are not followed or do not work as planned.

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    Enogex typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering and transportation systems; therefore, volumes of natural gas on its systems in the future could be less than anticipated.

        Enogex typically does not obtain independent evaluations of natural gas reserves connected to its systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, Enogex does not have independent estimates of total reserves dedicated to its systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to its gathering systems is less than Enogex anticipates and Enogex is unable to secure additional sources of natural gas, then the volumes of natural gas on Enogex's systems in the future could be less than Enogex anticipates. A decline in the volumes of natural gas on Enogex's systems could have a material adverse effect on our and Enogex's business, results of operations, financial condition and cash available for distribution.

    Enogex depends on certain key natural gas producer customers for a significant portion of its supply of natural gas and NGLs. The loss of, or reduction in volumes from, any of these customers could result in a decline in our and Enogex's cash available for distribution.

        Enogex relies on certain key natural gas producer customers for a significant portion of its natural gas and NGL supply. During 2006, Chesapeake Energy Marketing Inc., Apache Corporation, Scissortail Energy, LLC, Samson Resources Company and Burlington Resources Trading Inc. accounted for approximately 51% of Enogex's natural gas and NGL supply. During the first nine months of 2007, Chesapeake Energy Marketing Inc., Apache Corporation, Scissortail Energy, LLC, Devon Gas Services, L.P. and Samson Resources Company accounted for approximately 51% of Enogex's natural gas and NGL supply. The loss of the natural gas and NGL volumes supplied by these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on our and Enogex's business, results of operations, financial condition and cash available for distribution. For a discussion of Enogex's key natural gas producer customers, please see "Business—Our Business—Gathering and Processing—Customers and Contracts."

    Enogex depends on two customers for a significant portion of its firm intrastate transportation and storage services. The loss of, or reduction in volumes from, either of these customers could result in a decline in Enogex's transportation and storage services and our and Enogex's cash available for distribution.

        Enogex provides firm intrastate transportation and storage services to several customers on its system. Enogex's major customers are Oklahoma Gas & Electric Company, or OG&E, the largest electric utility in Oklahoma which serves the Oklahoma City market, and Public Service Company of Oklahoma, or PSO, which is the second largest electric utility in Oklahoma and serves the Tulsa market. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex has been providing natural gas storage services to OG&E since August 2002 when it acquired the Stuart Storage Facility. Enogex provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. During 2004, 2005, 2006 and the first nine months of 2007, revenues from Enogex's firm intrastate transportation and storage contracts were approximately $95.6 million, $95.0 million, $98.1 million and $79.3 million, respectively, of which $49.6 million, $47.6 million, $47.6 million and $35.5 million was attributed to OG&E and $13.3 million, $13.3 million, $13.3 million and $10.8 million, respectively, was attributed to PSO. Enogex's current contract with OG&E expires in April 2009. OG&E has indicated to us that it currently intends to consider competitive bids for gas transportation and storage services prior to the termination of Enogex's current agreement with OG&E, but it is not obligated to do so. Enogex's current contract with PSO expires in January 2013. Even though OG&E is a subsidiary of OGE Energy, there can be no assurance that the current contract with OG&E will be extended or replaced on similar terms or at all. Please see "Certain

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Relationships and Related Party Transactions—Contracts with Affiliates—Transportation and Storage Agreement with OG&E." The loss of all or even a portion of the intrastate transportation and storage services for either of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on our and Enogex's business, results of operations, financial condition and cash available for distribution.

    Enogex has historically depended on OGE Energy Resources, or OERI, for certain natural gas marketing and hedging services. To the extent that OERI does not continue to make such services available on similar terms, our and Enogex's cash available for distribution could be adversely affected.

        Enogex has historically utilized OERI for natural gas marketing, hedging, risk management and other related activities. For 2007, OERI charged a fee to Enogex of approximately $3.3 million for providing these services, including approximately $2.5 million charged to Enogex during the nine months ended September 30, 2007. Because OERI was a subsidiary of Enogex, the fee was not the result of arm's length negotiations. Following the offering, Enogex expects to continue to utilize OERI for these services under a Marketing and Administrative Services Agreement on terms that are more consistent with terms that would be negotiated with unaffiliated third parties. For instance, the fee that OERI will charge to Enogex in 2008 is expected to be approximately $5.2 million, which will include costs for credit support. To the extent those costs increase, the fee will also increase. The initial term of the Marketing and Administrative Services Agreement is expected to be three years. To the extent Enogex does not utilize OERI for these services, or the terms on which these services are provided differ from the terms historically used, our and Enogex's cash available for distribution could be adversely affected. Please see "Certain Relationships and Related Party Transactions—Contracts with Affiliates—Marketing and Administrative Services Agreement with OERI."

    Any negative change in OERI's creditworthiness could adversely affect Enogex's ability to engage in hedging transactions or adversely affect the prices and terms upon which hedging transactions occur.

        Enogex historically has conducted its hedging activities with OERI as its counterparty. OERI, in turn, has engaged in back-to-back hedging transactions with third parties. The willingness of those third parties to serve as counterparties on OERI's hedging transactions depends on OERI's creditworthiness. Any negative change in OERI's creditworthiness could adversely affect OERI's and Enogex's ability to enter into hedging transactions, or the prices and terms upon which such transactions may be effected.

    Enogex may not be successful in balancing its purchases and sales of natural gas and NGLs, which would increase its exposure to commodity price risk.

        In the normal course of business, Enogex purchases or retains from producers and other customers some of the natural gas and NGLs that flow through its natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. Enogex may not be successful in balancing its purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause Enogex's purchases and sales to be unbalanced. If Enogex's purchases and sales are unbalanced, it will face increased exposure to commodity price risk and we and Enogex could have increased volatility in our and its operating income and cash flows.

    If third-party pipelines and other facilities interconnected to Enogex's gathering or transportation facilities become partially or fully unavailable, our and Enogex's revenues and cash available for distribution could be adversely affected.

        Enogex depends upon third-party natural gas pipelines to deliver gas to, and take gas from, its transportation system. Enogex also depends on third-party facilities to transport and fractionate NGLs that it delivers to the third party at the tailgates of its processing plants. Fractionation is the separation

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of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. Since Enogex does not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our or Enogex's control. If any of these third-party pipelines or other facilities become partially or fully unavailable, our and Enogex's revenues and cash available for distribution could be adversely affected.

    Enogex is exposed to the credit risk of its key customers and counterparties, and any material nonpayment or nonperformance by its key customers and counterparties could adversely affect our and Enogex's financial results and cash available for distribution.

        Enogex is exposed to credit risks in its operations. Credit risk includes the risk that customers and counterparties, including OERI, that owe Enogex money will breach their obligations. If such parties to these arrangements fail to perform, Enogex may be forced to enter into alternative arrangements. In that event, our and Enogex's financial results and cash available for distribution could be adversely affected.

    Enogex faces certain human resource risks associated with the availability of trained and qualified labor to meet its future staffing requirements.

        Workforce demographic issues challenge employers nationwide and are of particular concern to the natural gas pipeline industry. The median age of natural gas pipeline workers is significantly higher than the national average. Over the next three years, approximately 21% of Enogex's current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our and Enogex's ability to manage and operate our and its business.

    Enogex will reimburse OGE Energy for costs associated with OGE Energy's defined benefit retirement plans, health care plans and other employee-related benefits related to Enogex's employees. Costs associated with these plans and benefits have been increasing and Enogex's reimbursement obligations may adversely affect our and Enogex's cash available for distribution.

        OGE Energy has defined benefit retirement and postretirement plans that cover substantially all of Enogex's employees. Enogex expects to continue to participate in these plans following completion of this offering. Pursuant to the omnibus agreement we will enter into with OGE Energy, our general partner and certain of their affiliates upon the closing of this offering, Enogex will reimburse OGE Energy for costs associated with those plans. OGE Energy's assumptions related to future costs, returns on investments and interest rates and other actuarial assumptions with respect to these defined benefit retirement and postretirement plans have a significant impact on our and Enogex's earnings and funding requirements.

        Employees of Enogex hired prior to February 1, 2000 participate in OGE Energy's defined benefit and postretirement plans. If these employees retire when they become eligible for retirement over the next several years, or if OGE Energy's plans experience adverse market returns on their investments, or if interest rates materially fall, OGE Energy's pension expense and contributions to the plans could rise substantially over historical levels. A portion of the expense and contributions is expected to be allocated to Enogex. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our and Enogex's results of operations. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our and Enogex's results of operations and consolidated financial condition. Those assumptions are outside of our control.

        In addition to the costs of OGE Energy's retirement plans, the costs of providing health care benefits to Enogex's employees and retirees have increased substantially in recent years. We believe

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that Enogex's employee benefit costs, including costs related to health care plans for Enogex's employees and former employees, will continue to rise. The increasing costs and funding requirements under the defined benefit retirement plan, health care plans and other employee benefits may adversely affect our and Enogex's cash available for distribution.

    Our industry is highly competitive, and increased competitive pressure could adversely affect our and Enogex's business and operating results.

        Enogex competes with similar enterprises in its respective areas of operation. Some of these competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than Enogex or us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services Enogex provides to its customers. In addition, Enogex's customers who are significant producers of natural gas may develop their own gathering, processing, transportation and storage systems in lieu of using Enogex's. Enogex's ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and customers. All of these competitive pressures could have a material adverse effect on our and Enogex's business, results of operations, financial condition and ability to make cash distributions.

    A change in the jurisdictional characterization of some of Enogex's assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of its assets, which may cause its revenues to decline and operating expenses to increase.

        Enogex's natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the Federal Energy Regulatory Commission, or the FERC, under the Natural Gas Act of 1938, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking and capacity release and its promotion of market centers, may indirectly affect intrastate markets. In recent years, the FERC has aggressively pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue these same objectives as it considers matters such as pipeline rates and rules and policies that may indirectly affect intrastate natural gas transportation business. For more information regarding regulation of Enogex's operations, please see "Business—Our Business—Transportation and Storage—Regulation."

    Enogex's natural gas transportation and storage operations are subject to regulation by the FERC pursuant to Section 311 of the NGPA, which could have an adverse impact on its ability to establish transportation and storage rates that would allow it to recover the full cost of operating its transportation and storage facilities, including a reasonable return, and an adverse impact on cash available for distribution.

        The FERC has jurisdiction over transportation rates charged by Enogex for transporting natural gas in interstate commerce under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Rates to provide such service must be "fair and equitable" under the NGPA and are subject to review and approval by the FERC at least once every three years. Enogex is currently charging rates for its Section 311 transportation services that were deemed fair and equitable under a rate settlement approved by the FERC for the period from January 1, 2005 until December 31, 2007.

        On October 1, 2007, Enogex made its required triennial filing for rates and in its filings proposed the new rates to be effective January 1, 2008. A number of interventions have been filed in response to Enogex's triennial filings and some of the intervening parties also filed protests. Enogex has not been able to reach a resolution of the issues with the protesting parties but expects to continue to have

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discussions with customers and to participate in settlement discussions with the FERC staff and other interested parties. Enogex has not yet placed the higher proposed rates into effect.

        Enogex cannot predict what the settlement terms will be or, if not settled, what determinations the FERC will make with respect to this proceeding or what impact, if any, those determinations might have on Enogex's ability to establish transportation rates that would allow Enogex to recover the fuel cost, including a reasonable return, of operating its transportation facilities and that portion of its storage capacity used in support of transaction services. Accordingly, Enogex cannot predict what impact, if any, such determinations could have on cash available for distribution.

        For more information regarding regulation of Enogex's operations, please see "Business—Our Business—Transportation and Storage—Regulation."

    Enogex's natural gas transportation, storage and gathering operations are subject to regulation by agencies in Texas and Oklahoma, and that regulation could have an adverse impact on its ability to establish rates that would allow it to recover the full cost of operating its facilities, including a reasonable return, and our cash available for distribution.

        State regulation of natural gas transportation, storage and gathering facilities generally focuses on various safety, environmental and, in some circumstances, nondiscriminatory access requirements and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, Enogex's natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Enogex's gathering operations also may be or become subject to safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on Enogex's operations, but Enogex could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect Enogex's business. Any such state regulation could have an adverse impact on our and Enogex's business and cash available for distribution.

    Recent events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our and Enogex's business, financial condition, access to capital and cash available for distribution.

        As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies, including those in the regulated and unregulated utility business, have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we and Enogex are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our or Enogex's business, financial condition, access to the capital markets or cash available for distribution. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or Enogex's operations specifically. Any new accounting standards could affect the way we and Enogex are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings, decreases in assets or increases in liabilities that could, in turn, affect our and Enogex's results of operations and cash available for distribution.

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    We and Enogex may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.

        Enogex's operations are, and operations of any of our future subsidiaries may be, subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act of 1976, or RCRA, and comparable state laws that impose requirements for the handling, storage, treatment and disposal of hazardous and solid waste from our facilities and (3) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA, also known as "Superfund," and comparable state laws that regulate and impose liability for the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by Enogex or locations to which Enogex has sent waste for disposal. Enogex may incur substantial costs in order to conduct its operations in compliance with these laws and regulations. For instance, Enogex may be required to obtain and maintain permits and approvals issued by various governmental authorities, limit or prevent releases of materials from its operations in accordance with these permits, or incur substantial liabilities for any pollution or contamination that may result from its operations. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining operations. Certain environmental regulations, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

        There is inherent risk of the incurrence of environmental costs and liabilities in Enogex's operations due to its handling of natural gas, air emissions related to its operations and historical industry operations and waste disposal practices. For example, an accidental release from one of Enogex's facilities could subject it to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Neither we nor Enogex may be able to recover these costs from insurance or from indemnification from OGE Energy. Please see "Business—Environmental Matters."

    We and Enogex may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

        Pursuant to the Pipeline Safety Improvement Act of 2002, the U.S. Department of Transportation, or the DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines. The regulations require operators to:

    identify potential threats to the public or environment, including "high consequence areas" on covered pipeline segments where a leak or rupture could do the most harm;

    develop a baseline plan to prioritize the assessment of a covered pipeline segment;

    gather data and identify and characterize applicable threats that could impact a covered pipeline segment;

    discover, evaluate and remediate problems in accordance with the program requirements;

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    continuously improve all elements of the integrity program;

    continuously perform preventative and mitigation actions;

    maintain a quality assurance process and management-of-change process; and

    establish a communication plan that addresses safety concerns raised by the DOT and state agencies, including the periodic submission of performance documents to the DOT.

        We currently estimate that Enogex will incur capital expenditures and operating costs of approximately $43.6 million between 2007 and 2011 to implement its pipeline integrity management program along certain segments of its natural gas pipelines. Approximately $11.7 million of these capital expenditures and operating costs were incurred during 2007. The estimated capital expenditures and operating costs include Enogex's estimates for the repair, remediation, prevention or other mitigation that may be determined to be necessary as a result of the testing program. At this time, we cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing that is required by the rule. Enogex will continue its pipeline integrity testing programs to assess and maintain the integrity of its pipelines. The results of these tests could cause Enogex to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

    Construction of new assets or modifications to existing systems may not result in revenue or cash flow increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our and Enogex's results of operations, financial condition and ability to make cash distributions.

        One of the ways we and Enogex intend to grow is through the construction of new midstream assets. The construction of additions or modifications to existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties beyond our and Enogex's control and may require the expenditure of significant amounts of capital. These projects, once undertaken, may not be completed on schedule or at the budgeted cost, or at all. Moreover, our and Enogex's revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if Enogex expands a new pipeline, the construction may occur over an extended period of time, and Enogex will not receive any material increases in revenues or cash flows until the project is completed. In addition, we or Enogex may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since neither we nor Enogex is engaged in the exploration for and development of natural gas, we and Enogex often do not have access to third-party estimates of potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent we or Enogex rely on estimates of future production in deciding to construct additions to systems, those estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve expected investment return, which could adversely affect our and Enogex's results of operations, financial condition and cash available for distribution. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to constructing new pipelines. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and we and Enogex may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our and Enogex's cash flows could be adversely affected.

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    Our ability to grow is dependent on our ability to access external expansion capital.

        We expect that Enogex will distribute all of its available cash to its members, including us, and we will distribute all of our available cash to our unitholders. As a result, we expect that we and Enogex will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent we or Enogex are unable to finance growth externally, our and Enogex's cash distribution policy will significantly impair our and Enogex's ability to grow. In addition, because we and Enogex distribute all available cash, our and Enogex's growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by us or Enogex to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that Enogex has to distribute to its members, including us, and that we have to distribute to our unitholders.

    If we or Enogex do not make acquisitions or are unable to make acquisitions on economically acceptable terms, our and Enogex's future growth will be limited.

        Our and Enogex's ability to grow depends, in part, on the ability to make acquisitions that result in an increase in our cash generated from operations per common unit. If we or Enogex are unable to make these accretive acquisitions either because: (1) we or Enogex are unable to identify attractive acquisitions or we are unable to negotiate purchase contracts on acceptable terms, (2) we or Enogex are unable to obtain financing on economically acceptable terms, or (3) we or Enogex are outbid by competitors, then our and Enogex's future growth and ability to increase distributions will be limited.

    Even if we and Enogex make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our cash generated from operations per common unit.

        Any acquisition involves potential risks, including, among other things:

    mistaken assumptions about volumes, revenues and costs, including synergies;

    an inability to integrate successfully the businesses that are acquired;

    a decrease in liquidity as a result of using a significant portion of available cash or borrowing capacity to finance the acquisitions;

    a significant increase in interest expense or financial leverage if additional debt is incurred to finance the acquisitions;

    the assumption of unknown liabilities for which we or Enogex are not indemnified or are indemnified inadequately;

    limitations on rights to indemnity from the seller;

    mistaken assumptions about the overall costs of equity or debt;

    the diversion of management's and employees' time and attention from other business concerns;

    unforeseen difficulties operating in new product areas or new geographic areas; and

    customer or key employee losses at the acquired businesses.

        If we or Enogex consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic,

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financial and other relevant information that we and Enogex will consider in determining the application of these funds and other resources.

    Enogex does not own all of the land on which its pipelines and facilities are located, which could disrupt its operations.

        Enogex does not own all of the land on which its pipelines and facilities have been constructed, and it is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights of way or if such rights of way lapse or terminate. Enogex obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies sometimes for a specific period of time. A loss of these rights, through Enogex's inability to renew right-of-way contracts or otherwise, could cause Enogex to cease operations temporarily or permanently on the affected land, increase costs related to continuing operations elsewhere, reduce our and its revenue and impair our and its ability to make cash distributions.

    Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our and Enogex's operations and financial results could be adversely affected.

        Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, including:

    damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, earthquakes, fires and other natural disasters and acts of terrorism;

    inadvertent damage from third parties, including construction, farm and utility equipment;

    leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and

    fires and explosions.

        These and other risks could result in substantial losses due to personal injury and loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our or Enogex's related operations.

        Enogex's insurance is currently provided under OGE Energy's insurance programs. Enogex is not fully insured against all risks inherent to its business. Enogex is not insured against all environmental accidents that might occur, which may include toxic tort claims. In addition, we or Enogex may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. Moreover, in some instances, significant claims by OGE Energy may limit or eliminate the amount of insurance proceeds available to us or Enogex. As a result of market conditions, premiums and deductibles for certain of OGE Energy's insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. If a significant accident or event occurs that is not fully insured, it could adversely affect our or Enogex's operations and financial results.

    Our and Enogex's debt levels may limit our and its flexibility in obtaining additional financing and in pursuing other business opportunities.

        At the closing of this offering, Enogex expects to enter into up to a $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes and to borrow approximately $13.9 million under this facility. The new credit facility is expected to include an accordion feature that would allow Enogex to seek an additional $250 million of lending commitments. Following this offering, we and Enogex will continue to have the ability to incur additional debt, subject to limitations in Enogex's credit facility. Enogex also currently expects to redeem its $400 million

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8.125% senior notes due 2010, and pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million, with a combination of approximately $300 million of short-term borrowings from OGE Energy, approximately $11.3 million of the $13.9 million of initial borrowings under its new credit facility and the approximately $130.2 million of net proceeds of this offering that we expect to contribute to Enogex for the anticipated repayment of that debt. Enogex expects to repay the amounts borrowed from OGE Energy for the redemption of its $400 million 8.125% senior notes due 2010 with the proceeds of an issuance of up to $300 million of new long-term debt.

        The levels of our and Enogex's debt could have important consequences, including the following:

    the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms;

    a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

    our and Enogex's debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

    our and Enogex's debt level may limit our flexibility in responding to changing business and economic conditions.

        Our and Enogex's ability to service our and its debt will depend upon, among other things, Enogex's future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our and Enogex's control. If operating results are not sufficient to service our or its current or future indebtedness, we and Enogex may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

    Enogex's new credit facility is expected to contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our or Enogex's control, that may limit Enogex's and its subsidiaries' businesses and financing activities.

        Enogex's new credit facility is expected to contain covenants and provisions that affect us, Enogex and its restricted subsidiaries, including, without limitation customary covenants and provisions:

    prohibiting Enogex from creating or incurring indebtedness if such incurrence would cause a breach of the consolidated leverage ratio described below and prohibiting Enogex's restricted subsidiaries from creating or incurring indebtedness (except for certain specified permitted indebtedness) in excess of the greater of (1) $200,000,000 and (2) 15% of the consolidated tangible net assets of Enogex and its restricted subsidiaries;

    prohibiting Enogex and its restricted subsidiaries from creating or incurring certain liens on their respective properties (subject to enumerated exceptions) securing indebtedness in excess of the greater of (1) $200,000,000 and (2) 15% of the consolidated tangible net assets of Enogex and its restricted subsidiaries;

    prohibiting Enogex from making distributions in certain circumstances, such as if any default or event of default occurs; provided that, among other things, so long as no matured event of default exists or would result therefrom, Enogex will be permitted to make distributions to fund distributions in amounts not to exceed the greater of (1) the amount by which Enogex's cash on

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      hand exceeds its current and anticipated needs and (2) the aggregate amount necessary to provide us with any shortfall in available cash to fund the minimum quarterly distributions to unitholders;

    prohibiting consolidations, mergers and asset transfers by Enogex and its restricted subsidiaries (subject to enumerated exceptions);

    prohibiting Enogex and its restricted subsidiaries from entering into transactions with affiliates (other than Enogex or any of its subsidiaries) other than on terms no less favorable to Enogex or any such subsidiary than those which would be obtainable in a transaction with an unrelated third party (subject to enumerated exceptions, including the making of distributions to us as described above); and

    prohibiting Enogex and its restricted subsidiaries from entering lines of business that are not substantially the same as those being currently conducted and other business reasonably related to those businesses.

        We also expect that the credit facility will require Enogex to maintain, as of the end of each fiscal quarter, a consolidated leverage ratio (consolidated funded indebtedness to consolidated EBITDA (in each case, as defined in the credit facility)) of no greater than 5.00-to-1.00 for any four consecutive quarters, and no greater than 5.50-to-1.00 for any three consecutive quarters subsequent to the consummation of one or more specified permitted acquisitions having an aggregate value greater than $25 million during the prior twelve-month period. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments will be limited to 20% of actual EBITDA.

        Any subsequent replacement of Enogex's credit facility or any future financing agreements could have similar or greater restrictions.

        These restrictions and covenants may restrict Enogex's ability to finance future operations or capital needs or to expand or pursue business activities. Enogex's ability to comply with the covenants and restrictions contained in its credit facility may be affected by events beyond our or Enogex's control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Enogex's ability to comply with these covenants may be impaired. If Enogex violates any of the restrictions, covenants, ratios or tests in its credit facility, a significant portion of Enogex's indebtedness may be declared or become immediately due and payable, and Enogex's lenders' commitment to make further loans to Enogex may be suspended or terminated. Enogex might not have, or be able to obtain, sufficient funds to make these accelerated payments. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

    Restrictions in Enogex's new credit facility are expected to limit its ability to make distributions upon the occurrence of certain events.

        Enogex's payment of principal and interest on its debt will reduce cash available for distributions to its members, including us. Enogex's new credit facility is expected to limit its ability to make distributions upon the occurrence of, among others things, certain customary events of default that affect Enogex and its restricted subsidiaries, including, without limitation:

    nonpayment of principal when due, nonpayment of interest, reimbursement obligations and stated fees within five business days of when due or nonpayment of other amounts within 30 days of when due;

    bankruptcy or insolvency with respect to Enogex or its material subsidiaries;

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    judgments against Enogex or its subsidiaries in excess of $40 million which are not paid, vacated or stayed within 45 days;

    failure by OGE Energy, together with its affiliates, to cease to own and control at least 51% of the voting equity of Enogex and to otherwise be able to exercise a controlling influence over Enogex;

    failure of representations and warranties of Enogex to be true and correct in any material respect when made;

    failure (subject, where applicable, to various cure periods) of Enogex to perform its undertakings;

    the occurrence of certain events relating to Enogex's and its subsidiaries' benefit and pension plans, to the extent such plans are entered into; and

    the documentation of the credit facility ceasing to be valid and enforceable or Enogex asserting that such agreements are, or taking any action to render such agreements, invalid or unenforceable.

        Any subsequent refinancing of Enogex's current debt or any new debt could have similar or more restrictive provisions.

    Due to Enogex's lack of asset and geographic diversification, adverse developments in its operations or operating areas would reduce our and its ability to make cash distributions.

        We and Enogex rely on revenues generated from Enogex's gathering, processing, transportation and storage facilities and related assets. Enogex's assets are primarily located in Oklahoma. Due to this lack of diversification in industry type and geographic location, an adverse development in Enogex's operations or operating areas would have a significantly greater impact on our and its financial condition and results of operations than if Enogex's assets were more geographically diverse.

    If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

        Our general partner has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general partner's efforts to maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

    We have no employees and, therefore, we rely on employees of OGE Energy and Enogex for the success of our and Enogex's businesses.

        We have no employees and, therefore, we rely on employees of OGE Energy and Enogex for the success of our and Enogex's businesses. Some of the executive officers of our general partner will be employees of OGE Energy and we will utilize a significant number of employees of OGE Energy and Enogex to operate our and Enogex's businesses. Upon the closing of this offering, we intend to enter into an omnibus agreement with OGE Energy pursuant to which employees of OGE Energy will perform administrative services for us such as legal, accounting, treasury, finance, investor relations,

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insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, facilities, fleet management and media services. Affiliates of OGE Energy conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to OG&E. As a result, there could be material competition for the time and effort of the executive officers and employees who provide services to us, OGE Energy and Enogex. If the employees of OGE Energy and Enogex, including the executive officers of our general partner, do not devote sufficient attention to the management and operation of our and Enogex's businesses, our and Enogex's financial results may suffer and our and Enogex's ability to make cash distributions may be impaired. For more information regarding the executive officers of our general partner, please see "Management—Directors and Executive Officers of OGE Enogex GP LLC."

    Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to Enogex's business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our and Enogex's results of operations and ability to make cash distributions.

        The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the natural gas midstream industry in general, and on us and Enogex in particular, cannot be known. Increased security measures taken by Enogex as a precaution against possible terrorist attacks have resulted in increased costs to Enogex's business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our and Enogex's operations in unpredictable ways, including disruptions of supplies and markets for Enogex's products, and the possibility that Enogex's infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

        Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us or Enogex to obtain. Moreover, the insurance that may be available to us and Enogex may be significantly more expensive than existing insurance coverage.

Risks Related to an Investment in Us

    OGE Energy controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including OGE Energy, may have conflicts of interest and may favor their own interests to your detriment.

        Following this offering, OGE Energy will indirectly own and control our general partner. Some of our general partner's directors and executive officers are directors or officers of OGE Energy. Therefore, conflicts of interest may arise between OGE Energy and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. These conflicts include, among others, the following situations:

    neither our partnership agreement nor any other agreement requires OGE Energy and its affiliates (other than our general partner) to pursue a business strategy that favors us. OGE Energy's directors and officers have a fiduciary duty to make decisions in the best interests of the owners of OGE Energy, which may be contrary to our interests;

    our general partner is allowed to take into account the interests of parties other than us, such as OGE Energy and its affiliates, in resolving conflicts of interest;

    OGE Energy and its affiliates (other than our general partner) are not limited in their ability to compete with us. Please see "—OGE Energy and certain of its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders" below;

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    some officers of OGE Energy who provide services to us also will devote significant time to the business of OGE Energy and will be compensated by OGE Energy for the services rendered to it;

    our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. Please see "—Our partnership agreement limits our general partner's fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties owed to our unitholders" below;

    our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

    in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units or to make incentive distributions or to accelerate the expiration of the subordination period;

    our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

    our partnership agreement permits us to classify up to $25 million as operating surplus, even if it would not otherwise be considered operating surplus. This provision allows our general partner to determine whether to cause us to pay distributions on its units and incentive distribution rights from cash not generated from operations. Our general partner may receive significant distributions that are funded by borrowings or asset sales and that might otherwise be treated as capital surplus, or a return of capital, to our partners and on which our general partner would not be entitled to receive incentive distributions;

    our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

    our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

    our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

    our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

        The board of directors of our general partner may resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus—Characterization of Cash Distributions" and "Conflicts of Interest and Fiduciary Duties."

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    Although our general partner, on our behalf as Enogex's managing member, controls Enogex, our general partner owes fiduciary duties to Enogex and Enogex's non-managing member, OGE Enogex Holdings LLC, which may conflict with the interests of us and our unitholders.

        Conflicts of interest may arise as a result of the relationships between us and our unitholders, on the one hand, and Enogex and its members, particularly its non-managing member, OGE Enogex Holdings LLC, on the other hand. OGE Enogex Holdings LLC will own a 75% membership interest in Enogex and will control our general partner. Our general partner, on our behalf, has fiduciary duties to manage Enogex in a manner beneficial to us. At the same time, our general partner has a fiduciary duty to manage Enogex in a manner beneficial to Enogex's non-managing member, OGE Enogex Holdings LLC. The resolution of these conflicts of interest may not always be in the best interest of us or our unitholders.

        For example, conflicts of interest may arise in the following situations:

    the allocation of shared overhead expenses to Enogex and us;

    the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Enogex or its subsidiaries, on the other hand;

    the determination and timing of the amount of cash to be distributed to Enogex's members and the amount of cash to be reserved for the future conduct of Enogex's business;

    the decision as to whether Enogex should make asset or business acquisitions or dispositions, and on what terms;

    the determination of the amount and timing of Enogex's capital expenditures;

    the determination of whether Enogex should use cash on hand, borrow or issue equity to raise cash to finance maintenance or expansion capital projects, repay indebtedness, meet working capital needs or otherwise; and

    any decision we make to engage in business activities independent of, or in competition with, Enogex.

    Cost reimbursements owed to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to our unitholders.

        Pursuant to the omnibus agreement we will enter into with OGE Energy, our general partner and certain of their affiliates upon the closing of this offering, we and Enogex will reimburse OGE Energy for the payment of operating expenses related to our and Enogex's operations and for the provision of various general and administrative services for our benefit. Payments for these services will be substantial and will reduce the amount of cash available for distribution to our unitholders. Please see "Certain Relationships and Related Party Transactions—Omnibus Agreement." Our general partner and its affiliates will be entitled to reimbursement for any other expenses they incur on our behalf and any other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business to the extent not otherwise covered by the omnibus agreement. In addition, under Delaware law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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    Fees owed by Enogex to OERI for hedging and risk management services could be substantial and will reduce Enogex's and our cash available for distribution.

        Pursuant to the Marketing and Administrative Services Agreement that Enogex will enter into with OERI following distribution of the capital stock of OERI to OGE Energy, Enogex will agree to pay to OERI an annual fee for the provision of natural gas marketing, hedging, risk management and other related services. For 2008, this fee is expected to be approximately $5.2 million, but may increase to cover additional credit support costs incurred by OGE Energy on behalf of OERI. These fees may reduce Enogex's and our cash available for distribution. Please see "Certain Relationships and Related Party Transactions—Contracts with Affiliates—Marketing and Administrative Services Agreement with OERI."

    We will be required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

        Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by the conflicts committee of our general partner at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

    After this offering, our wholly owned subsidiary will own a 25% membership interest in Enogex, and a wholly owned subsidiary of OGE Energy will own the remaining 75% membership interest. OGE Energy is not obligated to offer to us the remaining 75% interest in Enogex.

        After this offering, our wholly owned subsidiary will own a 25% membership interest in Enogex, and OGE Energy will retain, through a wholly owned subsidiary, the remaining 75% membership interest. OGE Energy is under no obligation to offer to us the opportunity to purchase over time the remaining 75% interest in Enogex. The board of directors of OGE Energy owes fiduciary duties to its shareholders, and not our unitholders, in making any decision to offer us this opportunity. Please see "Conflicts of Interest and Fiduciary Duties." Furthermore, the execution of any purchase agreement with respect to the acquisition by us from OGE Energy of any additional interest in Enogex will be subject to the approval of the conflicts committee of our general partner. The consummation of any such purchase will also be conditioned upon, among other things, our ability to finance the purchase and our obtaining all necessary consents. Please see "Certain Relationships and Related Party Transactions—Enogex LLC Limited Liability Company Agreement."

    OGE Energy and certain of its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

        Neither our partnership agreement nor the omnibus agreement between us, our general partner and OGE Energy and certain of its affiliates will prohibit OGE Energy and its affiliates (other than our general partner) from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, OGE Energy may acquire, construct or dispose of additional midstream or other assets

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in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. OGE Energy is a large, established participant in the energy business, and has significantly greater resources than we have, which factors may make it more difficult for us to compete with OGE Energy with respect to commercial activities as well as for acquisition candidates. As a result, competition from OGE Energy or its affiliates could adversely impact our results of operations and cash available for distribution to our unitholders. Please see "Conflicts of Interest and Fiduciary Duties."

    Any reductions in Enogex's credit ratings could increase Enogex's financing costs and the cost of maintaining certain contractual relationships.

        We cannot assure that any credit ratings of our subsidiaries, including Enogex, will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any future downgrade could increase the cost of short-term borrowings. Any downgrade could also lead to higher borrowing costs and, if below investment grade, could require us or our subsidiaries to post cash collateral or letters of credit.

    The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

        The credit and business risk profiles of our general partner and its owners may be factors in credit evaluations of a master limited partnership. This is because our general partner can exercise significant influence over our business activities, including our cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flows from us to service their indebtedness.

        OGE Energy, which indirectly owns our general partner, has indebtedness outstanding and is partially dependent on the cash distributions from its general partner and limited partner interests in us to service such indebtedness and pay dividends on its common stock. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.

    Our partnership agreement limits our general partner's fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties owed to our unitholders.

        Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and executive officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to OGE Energy, its ultimate parent. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws and also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties. For example, our partnership agreement:

    permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and in such cases it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our unitholders. Decisions made by our general partner in its individual capacity will be made by OGE Energy and not by the board of directors of our general partner. Examples include the exercise of its

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      limited call right, its rights to vote or transfer common units that it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership;

    provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

    generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be "fair and reasonable" to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

    provides that our general partner and its executive officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

    provides that in resolving conflicts of interest, it will be presumed that in making its decision that our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

        By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please see "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties."

    Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our unitholders in certain situations.

        Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset election (such amount is referred to herein as the "reset minimum quarterly distribution") and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

        In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that

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our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights."

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Because OGE Energy indirectly owns 100% of our general partner, the board of directors of our general partner will be chosen by OGE Energy. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Please see "—Following the completion of this offering, an affiliate of our general partner will own a sufficient number of our common units to allow it to block any attempt to remove our general partner." As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

    Following the completion of this offering, an affiliate of our general partner will own a sufficient number of our common units to allow it to block any attempt to remove our general partner.

        The unitholders will be unable initially to remove our general partner without its consent because an affiliate of our general partner will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner. Following the closing of this offering, an affiliate of our general partner will own 69.6% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. "Cause" is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. "Cause" does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder's dissatisfaction with our general partner's performance in managing us will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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    Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Unitholders' voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

    Our general partner's interest in us and control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective membership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and executive officers.

    If we cease to control Enogex, we may be deemed to be an investment company under the Investment Company Act of 1940.

        If we cease to manage and control Enogex and are deemed to be an investment company under the Investment Company Act of 1940 because of our wholly owned subsidiary's ownership of Enogex membership interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates.

    You will experience immediate and substantial dilution of $11.99 in tangible net book value per common unit.

        The assumed initial public offering price of $19.00 per unit exceeds our pro forma net tangible book value of $7.01 per unit. Based on the assumed initial public offering price of $19.00 per unit, you will incur immediate and substantial dilution of $11.99 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please see "Dilution."

    We may issue additional units without your approval, which would dilute your existing ownership interests.

        Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

    our unitholders' proportionate ownership interest in us will decrease;

    the amount of cash available for distribution on each unit may decrease;

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    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

    the ratio of taxable income to distributions may increase;

    the relative voting strength of each previously outstanding unit may be diminished; and

    the market price of the common units may decline.

    Affiliates of our general partner may sell common units in the public markets, which could have an adverse impact on the trading price of the common units.

        After the sale of the common units offered hereby, a subsidiary of OGE Energy will hold an aggregate of 4,829,214 common units and 12,329,214 subordinated units. Management of our general partner may also purchase common units in the offering. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units.

    Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Upon the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, an affiliate of our general partner will own approximately 39.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, an affiliate of our general partner will own approximately 69.6% of our aggregate outstanding common units. Affiliates of our general partner may acquire additional common units from us in connection with future transactions or through open-market or negotiated purchases. For additional information about this right, please see "The Partnership Agreement—Limited Call Right."

    Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in Oklahoma and Texas. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we may do business. You could be liable for any and all of our obligations as if you were a general partner if:

    a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or

    your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        For a discussion of the implications of the limitations of liability on a unitholder, please see "The Partnership Agreement—Limited Liability."

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    Unitholders may have liability to repay distributions that were wrongfully distributed to them.

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we refer to herein as the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

    Increases in interest rates could adversely impact the price of our common units.

        As with other yield-oriented securities, the market price of our common units is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment making decision purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units and our ability to issue additional equity to make acquisitions or for other purposes.

    There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop.

        Prior to the offering, there has been no public market for the common units. After the offering, there will be only 7,500,000 publicly traded common units, assuming no exercise of the underwriters' option to purchase additional units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

    The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be adversely affected by many factors, some of which are beyond our control, including our quarterly distributions, our quarterly or annual earnings or those of other companies in our industry, loss of a large customer, announcements by us, Enogex or competitors of significant contracts or acquisitions, changes in accounting standards, policies, guidance, interpretations or principles, general economic conditions, the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts, future sales of our common units, and other factors described in these "Risk Factors."

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    We will incur increased costs as a result of being a publicly traded partnership. If our actual incremental costs of being a publicly traded partnership are higher than we currently estimate, our ability to make cash distributions may be adversely affected.

        We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting, corporate governance and other expenses that we did not incur as a private company. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements. We have included $2.1 million of estimated incremental costs per year, some of which will be allocated to us by OGE Energy and its affiliates, associated with being a publicly traded partnership for purposes of our financial forecast included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. Since our incremental costs of being a public company directly reduce our cash available for distribution, if our actual incremental costs of being a publicly traded partnership are higher than we currently estimate, our ability to make cash distributions may be adversely affected.

Tax Risks to Common Unitholders

        In addition to reading the following risk factors, you should read the information under the caption "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.

    Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS treats us as a corporation or we become subject to a material amount of additional entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

        Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we will be subject to a new entity-level tax, the Texas margin tax, at an effective rate of up to 0.7% on the portion of our gross income that is apportioned to Texas. Imposition of such a tax on us by Texas or any other state, will reduce the cash available for distribution to you. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly

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distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

    The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

    We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

    An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution to our unitholders.

    You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

        Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

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    Tax gain or loss on the disposition of our common units could be more or less than expected.

        If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

    Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in our common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.

    We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

        Because we cannot match transferors and transferees of common units, we will take depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please see "Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election."

    We may adopt certain valuation methodologies that could result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under such valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

48


        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

    You will likely be subject to state and local taxes and return filing requirements where you do not live as a result of investing in our common units.

        In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, now or in the future, even if you do not live in any of those jurisdictions. You likely will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own property and conduct business in Oklahoma and Texas. Currently, Texas does not impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

    The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which could result in a deferral of depreciation and amortization deductions allowable in computing our taxable income. Please see "Material Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

49



USE OF PROCEEDS

        We expect to receive net proceeds from this offering of approximately $132.7 million, after deducting underwriting discounts and commissions and a structuring fee but before paying offering expenses. We base this amount on an assumed initial public offering price of $19.00 per common unit and assuming no exercise of the underwriters' option to purchase additional common units. We intend to use the net proceeds of this offering to pay approximately $2.5 million of expenses associated with the offering and related formation transactions and contribute the remaining net proceeds to Enogex. Enogex anticipates using those proceeds, together with approximately $300 million of short-term borrowings from OGE Energy, approximately $13.9 million of borrowings under its new credit facility and approximately $1.9 million of cash on hand, to:

    redeem its $400 million 8.125% senior notes due 2010, including payment of approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million; and

    pay approximately $4.5 million in fees and expenses related to Enogex's new credit facility and an issuance of up to $300 million of new long-term debt, the proceeds of which will be used to repay the short-term borrowings from OGE Energy.

        The structuring fee equal to 0.65% of the gross proceeds of this offering, or approximately $            , will be paid to UBS Securities LLC for evaluation, analysis and structuring of our partnership.

        If the underwriters' option to purchase additional common units is exercised, we intend to contribute the additional net proceeds to Enogex to pay a portion of the make-whole premium and of the fees described above, or repay short-term borrowings incurred to pay such premium and fees, and to use the balance to fund future capital expenditures and working capital and for other corporate purposes. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 8,625,000 common units, representing an aggregate 32.8% limited partner interest in us, and our general partner will retain its 2% general partner interest in us. In addition, because the contribution of those additional net proceeds would be considered a capital contribution from us to Enogex, our interest in Enogex following that contribution would increase to approximately 26% and OGE Energy's interest in Enogex would decrease to approximately 74%.

        An increase or decrease in the assumed public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions, the structuring fee and offering expenses payable by us, to increase or decrease by approximately $7.0 million.

50



CAPITALIZATION

        The following table shows:

    the capitalization of Enogex Predecessor as of September 30, 2007;

    our pro forma capitalization as of September 30, 2007 that reflects Enogex's distribution of the shares of OERI and dividend of outstanding advances to OERI to OGE Energy (which we refer to as the distribution adjustment);

    our pro forma capitalization as of September 30, 2007 that reflects the following adjustments (which we refer to as the formation adjustments):

    the reincorporation under the laws of the State of Delaware of Enogex Inc., which is currently an Oklahoma corporation, and the conversion of Enogex Inc. to Enogex LLC, a Delaware limited liability company;

    Enogex's conversion of outstanding intercompany loans to OGE Energy to a dividend from Enogex to OGE Energy of approximately $87.4 million;

    OGE Energy's contribution to our wholly owned subsidiary of a membership interest in Enogex;

    our issuance to OGE Enogex Holdings LLC, a wholly owned subsidiary of OGE Energy, of 4,829,214 common units and 12,329,214 subordinated units, collectively representing a 68.2% limited partner interest in us;

    our issuance to our general partner, a subsidiary of OGE Energy, of a 2% general partner interest in us and all of our incentive distribution rights;

    Enogex's entry into a new $250 million credit facility for working capital, capital expenditures, including acquisitions, and other corporate purposes, and borrowings under that credit facility of approximately $13.9 million;

    the redemption of Enogex's existing $400 million 8.125% senior notes due 2010 and payment of approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million; and

    Enogex's issuance of $300 million of new long-term debt; and

    our pro forma capitalization as of September 30, 2007 that reflects the distribution adjustment and the formation adjustments, this offering and the application of the net proceeds from this offering as described under the caption "Use of Proceeds" (which we refer to as the transaction adjustments).

        We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. For a description of the pro forma adjustments, please see our unaudited pro forma consolidated financial statements and accompanying notes included elsewhere in this prospectus beginning on page F-2. You should also read this table in conjunction with "Summary—Formation Transactions and Partnership Structure" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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  As of September 30, 2007
 
 
  Historical
  Pro Forma,
including
Distribution
Adjustment

  Pro Forma,
including
Formation
Adjustments

  Pro Forma,
including
Transaction
Adjustments

 
 
  (in millions)

 
Cash   $ 87.6   (a) $ 85.9   $ (130.2 ) $  
Non-controlling interest             398.0     398.0  
Long-term debt(b)     403.0     403.0     314.9     314.9  
Equity:                          
  Owner's equity(c)     416.7     384.2          
  Held by public:                          
    Common units                 130.2  
  Held by affiliates of OGE Energy:                          
    Common units             25.0     25.0  
    Subordinated units             63.6     63.6  
    General partner interest             2.5     2.5  
  Accumulated other comprehensive loss     (36.4 )   (39.4 )   (39.4 )   (39.4 )
   
 
 
 
 
      Total equity     380.3     344.8     51.7     181.9  
   
 
 
 
 
Total capitalization   $ 783.3   $ 747.8   $ 366.6   $ 496.8  
   
 
 
 
 

(a)
Includes outstanding intercompany loans from Enogex to OGE Energy of approximately $85.7 million.

(b)
Includes $1.0 million of long-term debt due within one year.

(c)
Includes $151.5 million of retained earnings.

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DILUTION

        Dilution is the difference between the offering price paid by the purchasers of common units sold in this offering and the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $19.00, on a pro forma basis as of September 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $176.4 million, or $7.01 per common unit. Net tangible book value excludes $5.5 million of net intangible assets. Purchasers of common units in this offering will experience an immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit       $ 19.00
  Pro forma net tangible book value per common unit before the offering(1)   5.11      
  Increase in pro forma net tangible book value per common unit attributable to purchasers in the offering   1.90      
Less:          
  Pro forma net tangible book value per common unit after the offering(2)         7.01
       
Immediate dilution in pro forma tangible net book value per common unit to new investors(3)       $ 11.99
       

    (1)
    Determined by dividing the number of units (4,829,214 common units, 12,329,214 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 503,233 units) to be issued to affiliates of OGE Energy for the contribution of a 25% membership interest in Enogex to our wholly owned subsidiary in connection with this offering into the net tangible book value of the contributed assets and liabilities. The number of units represented by the 2% general partner interest is determined by multiplying the total number of units deemed to be outstanding, (i.e., the total number of common and subordinated units outstanding divided by 98%) by the 2% general partner interest.

    (2)
    Determined by dividing the total number of units to be outstanding after the offering (12,329,214 common units, 12,329,214 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 503,233 units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering. The number of units represented by the 2% general partner interest is determined by multiplying the total number of units deemed to be outstanding, (i.e., the total number of common and subordinated units outstanding divided by 98%) by the 2% general partner interest.

    (3)
    If the initial public offering price were to increase or decrease by $1.00 per common unit, immediate dilution in tangible net book value per common unit would not change after giving effect to the corresponding change in our pro forma use of proceeds.

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        The following table sets forth the number of units that we will issue and the total consideration contributed to us by affiliates of OGE Energy (including our general partner) and by the purchasers of our common units in this offering upon consummation of the transactions contemplated by this prospectus:

 
  Units Acquired
  Total Consideration
 
 
  Number
  Percent
  Amount
  Percent
 
Affiliates of OGE Energy(1)(2)   17,661,661   70.2 % $ 91,158,054   39.0 %
New investors   7,500,000   29.8 % $ 142,500,000   61.0 %
   
 
 
 
 
  Total   25,161,661   100.0 % $ 233,658,054   100.0 %
   
 
 
 
 

    (1)
    Upon completion of the transactions contemplated by this prospectus, our general partner and its affiliates will own 4,829,214 common units, 12,329,214 subordinated units and the 2% general partner interest, which has a dilutive effect equivalent to 503,233 units. The number of units represented by the 2% general partner interest is determined by multiplying the total number of units deemed to be outstanding, (i.e., the total number of common and subordinated units outstanding divided by 98%) by the 2% general partner interest.

    (2)
    The assets and liabilities contributed by affiliates of OGE Energy were recorded at historical cost in accordance with GAAP. The net investment of OGE Energy, as of September 30, 2007, after giving effect to the application of the net proceeds of this offering, are set forth in the following table:

 
  (in millions)
 
Book value of net assets contributed   $ 132.6  
  Distribution to Enogex   $ (41.5 )
   
 
Total consideration   $ 91.1  
   
 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please see "—Assumptions and Considerations" below. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

        For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma consolidated financial statements included elsewhere in this prospectus.

General

    Rationale for Our Cash Distribution Policy

        Our partnership agreement requires us to distribute all of our available cash quarterly. Our available cash is our cash on hand, including cash from borrowings, at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures, hedging activities and operational needs. We intend to fund a portion of our capital expenditures with borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing rather than retaining our available cash.

    Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

        There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

    Our cash flow initially will depend completely on Enogex's distributions to us as one of its members. Our general partner, on our behalf as Enogex's managing member, has the authority to determine the amount of Enogex's monthly distributions, including the amount of cash reserves not distributed. Our general partner has a fiduciary duty to make decisions with respect to Enogex in the best interest of its members, including its non-managing member, OGE Enogex Holdings LLC. Our general partner's decision to make distributions, if any, and the amount of those distributions, if any, could result in a reduction in cash distributions to our unitholders from levels we currently anticipate pursuant to our stated distribution policy.

    Our distribution policy may be affected by restrictions on distributions under the credit facility that Enogex expects to enter into at the closing of this offering. That credit facility is expected to contain covenants requiring it to maintain certain financial ratios and tests. Should Enogex be unable to satisfy these restrictions or if Enogex is otherwise in default under the credit facility, it would be prohibited from making cash distributions to us, which would materially hinder our ability to make cash distributions to our unitholders, notwithstanding our stated cash distribution policy.

    The board of directors of our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to our unitholders from levels we currently anticipate.

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the consent of our general partner and

55


      the approval of the public common unitholders as provided in our partnership agreement, our partnership agreement can be amended with the approval of a majority of the outstanding common units (including common units held by affiliates of OGE Energy) and Class B units issued upon the reset of incentive distribution rights, if any, after the subordination period has ended, voting as a class. At the closing of this offering, a wholly owned subsidiary of OGE Energy will own our general partner and approximately 69.6% of our outstanding common units and subordinated units.

    Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

    Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to increases in our or Enogex's operating or general and administrative expense, principal and interest payments on our or Enogex's outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

        Our ability to make distributions to our unitholders depends on the performance of Enogex and its ability to distribute funds to us. Upon the closing of this offering, our 25% interest in Enogex will be our only cash-generating asset. The ability of Enogex to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable limited liability company laws and other laws and regulations.

    Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

        We expect that Enogex will distribute all of its available cash to its members, including us, and we will distribute all of our available cash to our unitholders. As a result, we expect that we and Enogex will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent we or Enogex are unable to finance growth externally, our and Enogex's cash distribution policy will significantly impair our and Enogex's ability to grow. In addition, because we and Enogex distribute all of our available cash, our and Enogex's growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by us or Enogex to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that Enogex has to distribute to its members, including us, and that we have to distribute to our unitholders.

Our Initial Distribution Rate

        Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.3375 per unit per complete quarter, or $1.35 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter through December 31, 2008. This equates to an aggregate cash distribution of $8.5 million per quarter or $34.0 million per year, in each case based on the number of common units, subordinated units and the 2% general partner interest to be outstanding immediately after completion of this offering. If the underwriters' option to purchase additional common units is exercised in full, the

56



ownership interest of the public unitholders will increase to 8,625,000 common units representing an aggregate 32.8% limited partner interest in us and our aggregate cash distribution would be $8.9 million per quarter or $35.5 million per year. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy."

        As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner's initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest if we issued additional units. If the underwriters' option is exercised in this offering and additional common units are issued, however, our general partner will maintain its initial 2% interest and will not be required to make a capital contribution to us.

        The table below sets forth the assumed number of outstanding common units (assuming no exercise and full exercise of the underwriters' option to purchase additional common units) and subordinated units and the general partner interest upon the closing of this offering and the aggregate distribution amounts payable during the year following the closing of this offering at our initial distribution rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis).

 
  No Exercise of the Underwriters' Option to Purchase Additional Units
  Full Exercise of the Underwriters' Option to Purchase Additional Units
 
   
  Distributions
   
  Distributions
 
  Number of Units
  Number of Units
 
  One Quarter
  Four Quarters
  One Quarter
  Four Quarters
Publicly held common units   7,500,000   $ 2,531,250   $ 10,125,000   8,625,000   $ 2,910,938   $ 11,643,750
Common units held by an affiliate of OGE Energy   4,829,214   $ 1,629,860   $ 6,519,439   4,829,214   $ 1,629,860   $ 6,519,439
Subordinated units held by an affiliate of OGE Energy   12,329,214   $ 4,161,110   $ 16,644,439   12,329,214   $ 4,161,110   $ 16,644,439
General partner interest held by an affiliate of OGE Energy(1)   503,233   $ 169,841   $ 679,364   526,192   $ 177,589   $ 710,359
   
 
 
 
 
 
Total   25,161,661   $ 8,492,061   $ 33,968,242   26,309,620   $ 8,879,497   $ 35,517,987
   
 
 
 
 
 

(1)
The number of general partner units is determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98%) by the general partner's 2% general partner interest.

        The subordination period generally will end if we have earned and paid at least $1.35 on each outstanding unit and made the corresponding distribution on the 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010. If we have earned and paid at least $0.50625 (150% of the minimum quarterly distribution) on each outstanding common unit and subordinated unit and made the corresponding distribution on the 2% general partner interest for each quarter for four consecutive quarters, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our partnership agreement requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, comply with applicable law, comply with any of our debt

57



instruments or other agreements or provide for future distributions to our unitholders for any one or more of the upcoming four quarters. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions." The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash Enogex generates from its business and distributes to its members, including us.

        If distributions on our common units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future except that, to the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to make cash distributions to holders of our common units at the initial distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please see "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware Act or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including these related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith.

        Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement.

        We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month, beginning May 15, 2008. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution amount for the period from the closing of this offering through March 31, 2008 based on the actual length of the period.

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.3375 per unit each quarter through the quarter ending December 31, 2008. In those sections, we present two tables, consisting of:

    "Statement of Minimum Estimated Adjusted EBITDA for the Year Ending December 31, 2008," in which we demonstrate our ability to generate the minimum estimated Adjusted EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the year ending December 31, 2008.

    "Pro Forma Cash Available for Distribution," in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2006 and the twelve months ended September 30, 2007, which is derived from and should be read in conjunction with the unaudited pro forma consolidated financial statements of OGE Enogex Partners L.P. included elsewhere in this prospectus, which unaudited pro forma financial statements are based on the audited historical consolidated financial statements of Enogex Predecessor for the year ended December 31, 2006 and the unaudited historical condensed consolidated financial statements of Enogex Predecessor for the nine months ended September 30, 2007, as adjusted to give pro forma effect to the transactions to be completed at the closing of the offering, including:

    the distribution by Enogex of the shares of OERI to OGE Energy;

    the dividend by Enogex of outstanding advances to OERI to OGE Energy;

58


      the conversion of Enogex Inc. to a Delaware limited liability company;

      the conversion of outstanding intercompany loans from Enogex to OGE Energy to a dividend from Enogex to OGE Energy;

      our ownership of a 25% membership interest in Enogex;

      the issuance by us of common units to the public assuming the underwriters exercise in full their option to purchase additional common units;

      the payment of underwriting discounts and commissions, the structuring fee and other offering expenses;

      the contribution by us of the proceeds of this offering to Enogex to allow for the redemption by Enogex of a portion of its existing $400 million 8.125% senior notes due 2010 and the refinancing by Enogex of those senior notes; and

      interest expense associated with short-term borrowings from OGE Energy to redeem a portion of Enogex's $400 million 8.125% senior notes due 2010 and with borrowings under Enogex's new credit facility.

        The "Statement of Minimum Estimated Adjusted EBITDA for the Year Ending December 31, 2008" and "Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and the Twelve Months Ended September 30, 2007" assume the underwriters exercise in full their option to purchase additional common units. If the underwriters do not exercise this option, our interest in Enogex would be 25% and OGE Energy's interest in Enogex would be 75%. If the underwriters exercise in full this option, we intend to contribute the additional net proceeds to Enogex, which would increase our interest in Enogex to approximately 26% and decrease OGE Energy's interest to approximately 74%.

Minimum Estimated Adjusted EBITDA for the Year Ending December 31, 2008

        Set forth below is a Statement of Minimum Estimated Adjusted EBITDA that reflects our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the year ending December 31, 2008, based on assumptions we believe to be reasonable. Adjusted EBITDA is defined as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. Our minimum estimated Adjusted EBITDA is prepared on a basis consistent with the accounting principles used in the historical consolidated financial statements of Enogex Predecessor.

        The Statement of Minimum Estimated Adjusted EBITDA reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take in order to make the minimum quarterly distribution on all our outstanding units for the year ending December 31, 2008. The assumptions disclosed in "—Assumptions and Considerations" below are those that we believe are significant to generate our minimum estimated Adjusted EBITDA. We believe our actual results of operations and cash flows will be sufficient to generate the minimum estimated Adjusted EBITDA, but we can give you no assurance that our minimum estimated Adjusted EBITDA will be achieved. There will likely be differences between our minimum estimated Adjusted EBITDA and our actual results and those differences could be material. If the minimum estimated Adjusted EBITDA is not achieved, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy or at all.

        Assuming the underwriters exercise in full their option to purchase additional common units, in order to fund distributions to all of our common and subordinated unitholders at our initial rate of $0.3375 per unit per quarter (or $1.35 per unit on an annualized basis) for the year ending

59



December 31, 2008, our minimum estimated Adjusted EBITDA for the year ending December 31, 2008 must be at least $218.8 million.

        The Statement of Minimum Estimated Adjusted EBITDA and related assumptions are forward-looking statements and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus and together with "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Statement of Minimum Estimated Adjusted EBITDA and related assumptions have been prepared by and are the responsibility of our management. Neither Ernst & Young LLP, our independent registered public accounting firm, nor any other independent accountants have compiled, examined or performed any procedures with respect to the Statement of Minimum Estimated Adjusted EBITDA and related assumptions contained herein, nor have they expressed any opinion or given any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the Statement of Minimum Estimated Adjusted EBITDA and related assumptions. Ernst & Young LLP reports included in this prospectus relate to the historical financial information of Enogex Predecessor. Those reports do not extend to the Statement of Minimum Estimated Adjusted EBITDA and related assumptions and should not be read to do so.

        When considering the Statement of Minimum Estimated Adjusted EBITDA for the year ending December 31, 2008, you should keep in mind the risk factors and other cautionary statements under the heading "Risk Factors" and elsewhere in this prospectus. Any of the risks discussed in this prospectus could cause our actual results of operations to vary significantly from those supporting the Statement of Minimum Estimated Adjusted EBITDA.

        We are providing the Statement of Minimum Estimated Adjusted EBITDA and related assumptions to supplement our historical and pro forma consolidated financial statements in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the year ending December 31, 2008 at our stated initial distribution rate. Please see "—Assumptions and Considerations" below for further information as to the assumptions we have made for the financial forecast.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating minimum estimated Adjusted EBITDA or to update those assumptions to reflect events or circumstances after the date of the effectiveness of the registration statement of which this prospectus is a part. Therefore, we caution you not to place undue reliance on this information.


OGE Enogex Partners L.P.
Statement of Minimum Estimated Adjusted EBITDA

(unaudited)

  Year Ending
December 31, 2008

 
 
  (in millions)

 
Revenues   $ 1,065.0  
Cost of goods sold     685.3  
Segment gross margin on revenues:        
  Gathering and processing segment     242.9  
  Transportation and storage segment     136.8  
   
 
    Total segment gross margin on revenues     379.7  
Expenses:        
  Other operation and maintenance(1)   $ 130.9  
  Depreciation     51.5  
  Taxes other than income     16.8  
   
 

60


    Total expenses     199.2  
Operating income     180.5  
  Other expense     (4.4 )
  Interest expense, net(2)     (27.1 )
   
 
Income from continuing operations before non-controlling interest     149.0  
Non-controlling interest in income(3)     (111.3 )
   
 
Net income     37.7  
Adjustments to reconcile net income to minimum estimated Adjusted EBITDA:        
Add:        
  Depreciation     51.5  
  Interest expense, net(2)     27.1  
  Non-controlling interest in income(3)     111.3  
Less:        
  Cash reserves(3)(4)     (8.8 )
   
 
Minimum Estimated Adjusted EBITDA(3)(5)     218.8  
Adjustments to reconcile minimum estimated Adjusted EBITDA to minimum estimated cash available for distribution:        
Less:        
  Cash interest expense     (30.2 )
  Maintenance capital expenditures(6)     (23.0 )
  Expansion capital expenditures     (168.1 )
Add:        
  Share of publicly traded partnership expenses(7)     1.1  
  Borrowings to fund expansion capital expenditures     161.5  
  Cash on hand at offering date     6.6  
   
 
Cash available for distribution from Enogex     166.7  
Less:        
  Non-controlling interest in cash available for distribution(3)     (130.1 )
  Share of publicly traded partnership expenses(7)     (1.1 )
   
 
Minimum estimated cash available for distribution(3)   $ 35.5  
   
 
Annual minimum cash distributions to:        
  Publicly held common units   $ 11.7  
  Common units held by an affiliate of OGE Energy     6.5  
  Subordinated units held by an affiliate of OGE Energy     16.6  
  General partner interest     0.7  
   
 
Total annual minimum cash distributions(3)   $ 35.5  
   
 

(1)
Includes publicly traded partnership expenses of $1.1 million. These partnership expenses are not expenses of Enogex, and therefore, are added back to income before non-controlling interest prior to calculating the non-controlling interest.

(2)
Under the provisions of Enogex's $400 million 8.125% senior notes due 2010 currently expected to be redeemed in connection with this offering, Enogex will pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million in connection with that redemption. As these items do not have a continuing impact, no adjustments for these items are provided in the Statement of Minimum Estimated Adjusted EBITDA.

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(3)
Non-controlling interest represents OGE Energy's 74% ownership interest in Enogex. This assumes the underwriters exercise in full their option to purchase additional common units. If the underwriters do not exercise their option to purchase additional common units, non-controlling interest in cash available for distribution, cash reserves, minimum estimated Adjusted EBITDA, minimum estimated cash available for distribution and total annual minimum cash distributions would be $130.8 million, $8.5 million, $219.1 million, $34.0 million and $34.0 million, respectively.

(4)
Represents a discretionary reserve to be used for reinvestment and other general partnership purposes.

(5)
Adjusted EBITDA is defined as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. Adjusted EBITDA is used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and others, to assess the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis; Enogex's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

    The economic substance behind the use of Adjusted EBITDA is to measure the ability of Enogex's assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to its members.

    Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

    Because Adjusted EBITDA has important limitations as an analytical tool, we believe that it is important that Adjusted EBITDA not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

(6)
The $23.0 million of maintenance capital expenditures for the forecast period represents estimated maintenance capital expenditures as defined in our partnership agreement. Our partnership agreement requires that an estimate of the maintenance capital expenditures necessary to maintain our operating capacity, asset base or operating income be subtracted from operating surplus each quarter as opposed to amounts actually spent. Due to the expected decline rate of the wells currently connected to Enogex's assets and those that we expect will be connected in the future, we expect that as our asset base grows the expenditures we will incur in the future to maintain our larger asset base will increase above the level estimated herein. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the conflicts committee.

(7)
We estimate that we will incur additional expenses of $2.1 million associated with being a publicly traded partnership, including but not limited to fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services, independent director compensation, additional finance and governance personnel and governance expenses, of which $1.1 million will be incurred by us and $1.0 million will be incurred by Enogex.

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Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006 and the Twelve Months Ended September 30, 2007

        If we had completed the transactions contemplated in this prospectus on January 1, 2006, and assuming the underwriters exercise in full their option to purchase additional common units, our pro forma cash available for distribution generated during the year ended December 31, 2006 and the twelve months ended September 30, 2007 would have been approximately $34.1 million and $32.3 million, respectively. These amounts would have been sufficient to make aggregate cash distributions equal to 100% of the minimum quarterly distribution of $0.3375 per unit per quarter (or $1.35 per unit on an annualized basis) on our common units but only 91.6% and 80.7% of the minimum quarterly distribution on our subordinated units for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively, assuming the underwriters exercise in full their option to purchase additional common units. To the extent that we would have elected to pay the full minimum quarterly distributions on the subordinated units during those periods, we believe we would have had access to sufficient borrowings to enable us to do so, provided that any such payments will have the effect of reducing operating surplus, including possibly a portion of the initial $25 million operating surplus basket.

        Unaudited pro forma cash available for distribution includes direct, incremental general and administrative expense that will result from operating as a separate publicly held limited partnership. These direct, incremental general and administrative expenses are expected to be approximately $2.1 million annually, are not subject to the caps contained in the omnibus agreement and include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services, independent director compensation, additional finance and governance personnel and governance expenses. These direct, incremental general and administrative expenditures, of which $1.1 million will be incurred by us and $1.0 million will be incurred by Enogex, are not reflected in the historical consolidated financial statements of Enogex Predecessor.

        We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

        The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended September 30, 2007, the amount of cash available for distribution that would have been available for distributions to our unitholders, assuming that this offering and the related transactions had been consummated on January 1, 2006 and assuming the underwriters exercise in full their option to purchase additional common units.


OGE Enogex Partners L.P.
Pro Forma Cash Available for Distribution(1)

(unaudited)

  Year
Ended
December 31, 2006

  Twelve Months
Ended
September 30, 2007

 
 
  (in millions)

 
Revenues   $ 832.9   $ 871.5  
Cost of goods sold     539.6     558.5  
   
 
 
Gross margin on revenues     293.3     313.0  
Other operation and maintenance(2)     103.0     113.7  

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Depreciation     42.1     44.9  
Impairment of assets     0.3     0.5  
Taxes other than income     15.5     14.9  
   
 
 
Operating income     132.4     139.0  
Interest income     2.9     0.9  
Other income     7.7     2.0  
Other expense     0.3     0.2  
Interest expense(3)     24.6     24.9  
   
 
 
Income from continuing operations before non-controlling interest     118.1     116.8  
Non-controlling interest in income(4)     88.2     87.3  
   
 
 
Pro forma net income(5)   $ 29.9   $ 29.5  
Adjustments to reconcile pro forma net income to pro forma Adjusted EBITDA:              
Add:              
  Depreciation     42.1     44.9  
  Interest expense, net(3)     21.7     24.0  
  Non-controlling interest in income(4)     88.2     87.3  
   
 
 
Pro forma Adjusted EBITDA(6)   $ 181.9   $ 185.7  
Adjustments to reconcile pro forma Adjusted EBITDA to pro forma cash available for distribution:              
Less:              
  Cash interest expense     (21.7 )   (24.0 )
  Maintenance capital expenditures(7)     (26.0 )   (34.4 )
  Expansion capital expenditures     (41.1 )   (79.5 )
Add:              
  Share of publicly traded partnership expenses(8)     1.1     1.1  
  Borrowings to fund expansion capital expenditures     41.1     79.5  
   
 
 
Pro forma cash available for distribution from Enogex     135.3     128.4  
Less:              
  Non-controlling interest in cash distributions(4)     (100.1 )   (95.0 )
  Share of publicly traded partnership expenses(8)     (1.1 )   (1.1 )
   
 
 
Pro forma cash available for distribution   $ 34.1   $ 32.3  
   
 
 
Minimum annual cash distributions to:              
  Publicly held common units   $ 11.7   $ 11.7  
  Common units held by an affiliate of OGE Energy     6.5     6.5  
  Subordinated units held by an affiliate of OGE Energy     16.6     16.6  
  General partner interest     0.7     0.7  
   
 
 
Total minimum annual cash distributions   $ 35.5   $ 35.5  
   
 
 
Shortfall of pro forma cash available for distribution   $ (1.4 ) $ (3.2 )
   
 
 

(1)
The pro forma financial data for the year ended December 31, 2006 and the twelve months ended September 30, 2007 reflects the pro forma effect of the distribution of the stock of OERI to OGE Energy.

(2)
Includes publicly traded partnership expenses of $1.1 million. These partnership expenses are not expenses of Enogex, and therefore, are added back to income before non-controlling interest prior to calculating the non-controlling interest.

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(3)
Under the provisions of Enogex's $400 million 8.125% senior notes due 2010 currently expected to be redeemed in connection with this offering, Enogex will pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million in connection with that redemption. As these items do not have a continuing impact, no adjustments for these items are provided in the accompanying unaudited pro forma consolidated statements of income.

(4)
Non-controlling interest represents OGE Energy's 74% ownership interest in Enogex. This assumes the underwriters exercise in full their option to purchase additional common units.

(5)
Reflects net income of the partnership for the periods presented after giving pro forma effect to the offering and the related transactions.

(6)
Adjusted EBITDA is defined as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. Adjusted EBITDA is used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and others, to assess the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis; Enogex's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

    The economic substance behind the use of Adjusted EBITDA is to measure the ability of Enogex's assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to its members.

    Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

    Because Adjusted EBITDA has important limitations as an analytical tool, we believe that it is important that Adjusted EBITDA not be considered in isolation or as a substitute for analysis of our results as reported under GAAP.

(7)
The $26.0 million and $34.4 million for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively, represent actual maintenance capital expenditures during those periods. Our partnership agreement requires that an estimate of the maintenance capital expenditures necessary to maintain our operating capacity, asset base or operating income be subtracted from operating surplus each quarter as opposed to amounts actually spent. Due to the expected decline rate of the wells currently connected to Enogex's assets and those that we expect will be connected in the future, we expect that as our asset base grows the expenditures we will incur in the future to maintain our larger asset base will increase above the actual levels set forth herein. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the conflicts committee.

(8)
We estimate that we will incur additional expenses of $2.1 million associated with being a publicly traded partnership, including but not limited to fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services, independent director compensation, additional finance and governance personnel and governance expenses, of which $1.1 million will be incurred by us and $1.0 million will be incurred by Enogex.

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Assumptions and Considerations

        The following discussion refers to 100% of Enogex, of which we will own an approximate 26% interest upon completion of this offering, assuming that the underwriters exercise in full their option to purchase additional common units. The subheading "Non-Controlling Interest in Net Income" describes the portion of income that is attributable to the approximate 74% non-controlling interest. If the underwriters do not exercise their option to purchase additional common units, we will own a 25% interest.

        All comparisons below are made to historical periods which have been adjusted on a pro forma basis to reflect the transactions contemplated herein, including the distribution of the stock of OERI to OGE Energy. The forecast has been prepared assuming full exercise of the underwriters' over-allotment option.

        We forecast Enogex's consolidated gross margin to be approximately $379.7 million for the year ending December 31, 2008 compared to $293.3 million and $313.0 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. Segment detail on the forecasted gross margin is provided below.

Transportation and Storage Gross Margin

        We forecast gross margin for Enogex's transportation and storage business to be approximately $136.8 million for the year ending December 31, 2008 compared to $125.6 million and $140.6 million for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively. Key factors impacting the forecasted increase in transportation and storage gross margin are:

    Approximately $98.7 million of the total forecasted transportation and storage gross margin is fixed fee based and is related to demand fees. The forecasted amount of $98.7 million is compared to $92.6 million and $99.7 million for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively. The increase relative to the year ended December 31, 2006 is primarily related to storage service contract renewals at more favorable rates due to volatility in the natural gas markets. The decrease relative to the twelve months ended September 30, 2007 is primarily due to lower demand fees on transportation services.

    Forecasted gross margin includes $20.0 million of low-pressure and high-pressure gas transportation fees associated with bundled gathering and transportation contracts compared to $16.8 million and $16.3 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The increase is due primarily to the transportation of expected higher gathered volumes.

    Forecasted gross margin also includes $7.0 million of interruptible and daily crosshaul transportation fees compared to $10.8 million and $10.7 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The decrease is primarily due to lower assumed crosshaul volumes due to capacity previously available for crosshaul that is expected to be utilized for new business in the Woodford Shale play and lower crosshaul rates.

    Forecasted gross margin excludes an $8.3 million lower of cost or market write down in 2006 as well as a gain of $1.1 million associated with imbalances for the year ended December 31, 2006 and a gain of $0.9 million for the twelve months ended September 30, 2007.

Gathering and Processing Gross Margin

        We forecast gross margin for Enogex's gathering and processing business to be approximately $242.9 million for the year ending December 31, 2008 compared to $167.6 million and $172.4 million

66



for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. Key factors impacting the forecasted increase in gathering and processing gross margin are:

    Forecasted fee-based gathering revenues of $76.1 million compared to $57.0 million and $61.4 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. This increase is primarily due to a forecasted increase in gathered volumes to 1.24 TBtu/d of natural gas for the year ending December 31, 2008 as compared to gathered volumes of 0.98 TBtu/d and 1.03 TBtu/d for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. This increase is being driven by recent and anticipated new well connects and gathering system expansions in the Woodford Shale play in southeastern Oklahoma and the Granite Wash play in western Oklahoma and the Texas Panhandle.

    Gross margin associated with the Atoka Midstream LLC joint venture is forecasted to be $11.6 million compared to $0.8 million for the twelve months ended September 30, 2007. The year ending December 31, 2008 is the first full calendar year of commercial operation. Atoka Midstream LLC was not in commercial operation during the year ended December 31, 2006.

    Gross margin associated with percent-of-liquids and keep-whole arrangements is forecasted to be $115.5 million compared to $76.0 million and $76.0 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The increase is primarily attributed to more favorable realized commodity prices and higher keep-whole volumes than in the prior periods.

    Gross margin associated with the sale of condensate, which is a by-product of the gathering process, is forecasted to be $16.3 million compared to $8.9 million and $10.1 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The increase is primarily attributed to more favorable realized commodity prices.

    Enogex's total processing inlet volumes is forecasted to be 0.63 TBtu/d for the year ending December 31, 2008 compared to inlet volumes of 0.54 TBtu/d and 0.56 TBtu/d for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. This increase is being driven by anticipated increased gathered volumes as a result of system expansions in the Woodford Shale play in southeastern Oklahoma and the Granite Wash play in western Oklahoma and the Texas Panhandle.

    Of the total forecasted processing volumes, Enogex's processing mix is forecasted to be approximately 24.2% percent-of-liquids and percent-of-proceeds, 40.4% keep-whole subject to a default processing fee, 28.4% "lean" keep-whole (natural gas which has a Btu content less than 1,080 per cubic foot) and 7.0% fixed fee, which approximates Enogex's mix of processing contracts for the year ended December 31, 2006 and the twelve months ended September 30, 2007.

    Sales of Enogex's equity portion of NGLs attributable to percent-of-liquids and percent-of-proceeds arrangements sold is forecasted to be 14.9 million gallons for the year ending December 31, 2008 compared to 14.2 million gallons and 16.4 million gallons for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The decrease during the forecast period compared to the twelve months ended September 30, 2007 is due to lower volumes processed under these arrangements.

    Sales of Enogex's equity portion of NGLs attributable to keep-whole arrangements sold is forecasted to be 265.7 million gallons for the year ending December 31, 2008 compared to 243.9 million gallons and 241.4 million gallons for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. This increase is being driven by recent and anticipated new well connects and gathering system expansions in the Woodford Shale play

67


      in southeastern Oklahoma and the Granite Wash play in western Oklahoma and the Texas Panhandle.

    Our forecast is based upon expected prices in Enogex's areas of operations. The average natural gas price for the regions in which Enogex operates is forecasted to be $7.32 per MMBtu for the year ending December 31, 2008. Our forecasted average natural gas price for the year ending December 31, 2008 represents a 21.6% and 24.0% increase over average historical gas prices for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The forward price as of December 31, 2007 was 8.6% lower than our forecasted price.

    Weighted average NGL prices are forecasted to be $1.207 per gallon for the year ending December 31, 2008. Our forecasted weighted average NGL prices for the year ending December 31, 2008 represent a 30.1% and 24.2% increase over average historical NGL prices for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The forward prices of NGLs as of December 31, 2007 were 12.8% higher than our forecasted prices.

    The result of our forecasted natural gas price, NGL prices, and applicable hedges is a forecasted realized commodity spread of $5.36 per MMBtu for the year ending December 31, 2008 as compared to $3.92 per MMBtu for the year ended December 31, 2006 and $4.33 per MMBtu for the twelve months ended September 30, 2007. If the forecasted commodity prices were equal to the forward prices as of December 31, 2007, the forecasted realized commodity spread would be $6.76 per MMBtu.

    Processing gross margin sensitivity due to commodity prices is not always expected to be linear due to factors such as ethane rejection, hedges in place and the absolute prices of the commodities that comprise the commodity spread. The table below reflects the effects on Enogex's gross margin and cash available for distribution of a 10% and 20% increase and decrease from the forecasted realized commodity spread.

 
   
  Incremental Change to Forecasted Amount
 
 
  Forecasted Amount
 
 
  +10%
  -10%
  +20%
  -20%
 
 
  (in millions, except commodity spread)

 
Realized commodity spread   $ 5.4   $ 0.54   $ (0.54 ) $ 1.08   $ (1.08 )
Gross margin   $ 379.7   $ 12.7   $ (12.7 ) $ 25.4   $ (25.4 )
Cash reserves   $ 8.8   $ 3.3   $ (3.3 ) $ 6.6   $ (6.6 )
Minimum quarterly cash distribution for the forecast period   $ 35.5                          
    Approximately 57% of Enogex's total processing commodity exposure is currently hedged. This 57% represents hedges on approximately 58% of Enogex's total expected keep-whole related

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      processing volumes and approximately 42% of its expected percent-of-liquid and percent-of-proceeds liquids volumes. These volumes are hedged as follows:

      The following hedges were placed for the year ending December 31, 2008 and are comprised of swaps and forwards. The NGL hedges are net short positions and natural gas hedges are net long positions.

Year Ending December 31, 2008

Commodity

  Volume
  Weighted-Average Price
Ethane(1)   50,400,000 gallons   $ 0.756 / gallon
Propane   29,080,800 gallons   $ 1.094 / gallon
Normal butane   8,215,200 gallons   $ 1.240 / gallon
Iso-butane   5,317,200 gallons   $ 1.280 / gallon
Natural gasoline   11,642,200 gallons   $ 1.594 / gallon
Natural gas   12,600,528 MMBtu   $ 7.511 / MMBtu

(1)    Entered into ethane hedges in October and November 2007.
      The following hedges were placed for the year ending December 31, 2008 and are comprised of purchased put options.

Year Ending December 31, 2008

Commodity

  Volume
  Weighted-Average Price
Propane   29,232,000 gallons   $ 0.966 / gallon
Normal butane   8,568,000 gallons   $ 1.091 / gallon
Iso-butane   5,544,000 gallons   $ 1.143 / gallon
Natural gasoline   11,592,000 gallons   $ 1.387 / gallon

Operation and Maintenance Expenses

        We forecast Enogex's consolidated operation and maintenance expenses to be approximately $130.9 million for the year ending December 31, 2008 compared to $103.0 million and $113.7 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively, based on the following significant assumptions:

    Increased salary and wage expense due to new positions in response to increased business activity.

    We estimate that Enogex will incur expenses of $3.3 million associated with natural gas marketing, hedging, risk management and other related services provided by OERI. Please see "Certain Relationships and Related Party Transactions—Contracts with Affiliates—Marketing and Administrative Services Agreement with OERI."

    We estimate that we and Enogex will incur additional expenses of $2.1 million associated with being a publicly traded partnership, including but not limited to fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services, independent director compensation, additional finance and governance personnel and governance expenses and estimated amounts payable to OGE Energy and its affiliates in connection with the omnibus agreement, of which $1.1 million will be incurred by us and $1.0 million will be incurred by Enogex. Please see "Certain Relationships and Related Party Transactions— Omnibus Agreement."

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Depreciation

        We forecast Enogex's depreciation to be approximately $51.5 million for the year ending December 31, 2008 compared to $42.1 million and $44.9 million in depreciation for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The increase is primarily due to increased investment in Enogex's assets located in the Texas Panhandle, western Oklahoma and southeastern Oklahoma areas.

Taxes Other than Income

        We forecast Enogex's taxes other than income to be approximately $16.8 million for the year ending December 31, 2008 compared to $15.5 million and $14.9 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The increase is primarily due to increased investment in Enogex's assets located in the Texas Panhandle, western Oklahoma and southeastern Oklahoma areas.

Other Expense

        We forecast Enogex's other expense to be approximately $4.4 million for the year ending December 31, 2008 compared to $10.3 million and $2.7 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The forecasted other expense is primarily attributable to the non-controlling interest of the partner of the Atoka Midstream LLC joint venture.

Non-Controlling Interest in Net Income

        We forecast Enogex's non-controlling interest in net income to be approximately $111.3 million for the year ending December 31, 2008 compared to $88.2 million and $87.3 million on a pro forma basis for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The non-controlling interest is based on OGE Energy's initial 74% indirect ownership of Enogex, assuming that the underwriters exercise in full their option to purchase additional common units. If the underwriters do not exercise their option to purchase additional units, OGE Energy will own a 75% interest and OGE Enogex Partners will own a 25% interest in Enogex.

Capital Expenditures

        We forecast total capital expenditures for the year ending December 31, 2008 to be $191.1 million based on the following assumptions:

    Maintenance capital expenditures are forecasted to be approximately $23.0 million. These forecasted expenditures include:

(in millions)

   
Reliability (including pipeline integrity)   $ 9.8
Well connects on Enogex's existing system     4.5
Regulatory compliance     2.7
Facilities and fleet     2.6
Technology improvements     2.3
Environmental     0.9
Other     0.2
   
  Total maintenance capital expenditures   $ 23.0
   

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    Expansion capital expenditures during the forecast period are forecasted to be approximately $168.1 million. These forecasted expenditures include:

(in millions)

   
Midcontinent Express and Boardwalk's Gulf Crossing expansion projects   $ 43.1
Western Oklahoma expansion     40.4
Woodford Shale expansion projects     38.4
Processing upgrades     20.0
Texas Panhandle expansion projects     2.3
Expansion and other     23.9
   
  Total expansion capital expenditures   $ 168.1
   

Financing

        Our forecast for the year ending December 31, 2008 is based on the following significant financing assumptions:

    Enogex redeems all of its existing $400 million 8.125% senior notes due 2010.

    Enogex funds the redemption, including payment of approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million, with a combination of approximately $300 million of short-term borrowings from OGE Energy and a portion of the net proceeds from this offering.

    Enogex repays the amounts borrowed from OGE Energy for the redemption of its $400 million 8.125% senior notes due 2010 with the proceeds of the issuance of $300 million in aggregate principal amount of senior notes.

    Enogex's interest expense is forecasted to be $27.1 million compared to $24.6 million and $24.9 million on a pro forma basis for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The forecasted amount assumes borrowings during the forecast period of $161.5 million under Enogex's new credit facility using an annual interest rate of 6.00% and the issuance of $300 million aggregate principal amount of senior notes with an assumed annual interest rate of 7.00%. The assumed interest rates reflect our best estimate of rates available under current market conditions however, market volatility could impact these estimates and cause interest expense to deviate from forecasted amounts. A 1.0% increase or decrease in the assumed annual interest rate with respect to Enogex's new credit facility would cause forecasted interest expense to increase or decrease by $1.0 million. A 1.0% increase or decrease in the assumed annual interest rate with respect to the new senior notes would cause forecasted interest expense to increase or decrease by $3.0 million. The forecasted amount also includes $2.0 million for credit support costs associated with natural gas marketing, hedging, risk management and other related services provided by OERI.

    Enogex will finance expected expansion capital expenditures using cash on hand as well as available capacity on its revolving credit facility. Enogex is expected to have $88.5 million of available borrowing capacity as of December 31, 2008.

Payments of Distributions to Non-Controlling Interest

        We forecast that distributions to OGE Energy's indirect 74% non-controlling interest in Enogex will be approximately $130.1 million for the year ending December 31, 2008.

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Payments of Distributions on Common Units, Subordinated Units and the 2% General Partner Interest

        We forecast that distributions on common units, subordinated units and the 2% general partner interest for the year ending December 31, 2008 will be approximately $35.5 million in the aggregate.

Regulatory, Industry and Economic Factors

        We forecast for the year ending December 31, 2008 based on the following significant assumptions related to regulatory, industry and economic factors:

    No material nonperformance or credit-related defaults by suppliers, customers or vendors will occur. There will not be any new federal, state or local regulation of the portions of the energy industry in which Enogex operates or any interpretation of existing regulation that in either case will be materially adverse to Enogex's business.

    No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated and material events will occur.

    There will not be any major adverse change in the midstream sector of the energy industry or in general economic conditions.

    Market, regulatory, insurance and overall economic conditions will not change substantially.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS

        Following completion of this offering, OGE Enogex Holdings LLC, a wholly owned subsidiary of OGE Energy, will own 4,829,214 common units and 12,329,214 subordinated units. In addition, OGE Enogex Holdings LLC will hold all of the membership interests in our general partner, and consequently will be entitled to all of the distributions that we make to OGE Enogex GP LLC, subject to the terms of the limited liability company agreement of OGE Enogex GP LLC and relevant legal restrictions.

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

    General

        Our partnership agreement requires that, no later than 45 days after the end of each quarter, beginning with the quarter ending March 31, 2008, we distribute all of our available cash to unitholders of record on the applicable record date.

    Definition of Available Cash

        We define available cash in the partnership agreement, and it generally means, for each fiscal quarter, the sum of all cash and cash equivalents on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own, including Enogex) plus all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own, including Enogex) resulting from working capital borrowings made after the end of the quarter, less the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including Enogex) established by our general partner to:

    provide for the proper conduct of our business (including reserves for future capital expenditures and for future credit needs of us and our subsidiaries);

    comply with applicable law, any of our debt instruments or other agreements; or

    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages for the next four quarters).

        Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners.

    Minimum Quarterly Distribution

        We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3375 per unit, or $1.35 on an annualized basis, to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

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    General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will be entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. Our general partner's 2% interest in us is represented by unit equivalents for allocation and distribution purposes. This general partner interest will be represented by 503,233 units equivalents (or 526,192 units equivalents if the underwriters exercise in full their option to purchase additional common units). Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest if we issue additional units. Our general partner's initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. If, however, the underwriters' option is exercised in this offering and additional common units are issued, our general partner will maintain its initial 2% interest and will not be required to make a capital contribution to us.

        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.3881 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on common units or subordinated units that it owns.

Operating Surplus and Capital Surplus

    General

        All cash distributed to unitholders will be characterized as either "operating surplus" or "capital surplus." Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

    Operating Surplus

        We define operating surplus in the partnership agreement, and for any period it generally means:

    $25 million (as described below); plus

    all cash receipts of us and our subsidiaries (including our proportionate share of cash receipts for certain subsidiaries we do not wholly own, including Enogex) after the closing of this offering, excluding cash from interim capital transactions, which include:

    borrowings that are not working capital borrowings;

    sales of equity and debt securities;

    sales or other dispositions of assets outside the ordinary course of business;

    capital contributions received; or

    corporate reorganizations or restructurings,

      provided the cash receipts from the termination of a commodity hedge or interest rate swap prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate swap; plus

    working capital borrowings (including our proportionate share of working capital borrowings for certain subsidiaries we do not wholly own, including Enogex) made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; plus

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    cash distributions paid on equity issued in connection with the construction or development of a capital improvement or replacement asset during the period beginning on the date that we or our subsidiaries enter into a binding commitment to commence the construction or development of such capital improvement or replacement asset and ending on the earlier to occur of the date the capital improvement or replacement asset is placed into service and the date that it is abandoned or disposed of; less

    all operating expenditures, including estimated maintenance capital expenditures, of us and our subsidiaries (including our proportionate share of operating expenditures of certain subsidiaries we do not wholly own, including Enogex) after the closing of this offering; less

    the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including Enogex) established by our general partner to provide funds for future operating expenditures; less

    all working capital borrowings (including our proportionate share of working capital borrowings for certain subsidiaries we do not wholly own, including Enogex) not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings.

        If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $25 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus.

        We define operating expenditures in the partnership agreement, and it generally means all of our cash expenditures (including our proportionate share of cash expenditures of certain subsidiaries we do not wholly own, including Enogex), including, but not limited to, taxes, reimbursements of expenses to our general partner, interest payments, payments made in the ordinary course of business under any interest rate hedge contracts or commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of a commodity hedge contract, such amounts will be amortized over the life of the applicable commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), repayments of working capital borrowings, estimated maintenance capital expenditures and specified non-pro rata purchases of partnership units, provided that operating expenditures will not include:

    repayments of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such repayment actually occurs;

    payments (including prepayments and prepayment penalties) of principal and premium on indebtedness other than working capital borrowings;

    actual maintenance capital expenditures;

    expansion capital expenditures;

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    investment capital expenditures;

    payment of transaction expenses relating to interim capital transactions; or

    distributions to partners.

        For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain over the long-term the operating capacity, asset base or operating income of us and our subsidiaries, and expansion capital expenditures are those capital expenditures that increase the operating capacity, asset base or operating income generated by capital assets. Examples of maintenance capital expenditures include expenditures required to maintain equipment reliability, storage and pipeline integrity and safety and to address environmental regulations. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction or development of a replacement asset and paid during the period that begins when we enter into a binding obligation to commence constructing or developing the replacement asset and ending on the earlier to occur of the date of any such replacement asset commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

        Because our maintenance capital expenditures can be very large and vary significantly in timing, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus each quarter. Accordingly, to eliminate the effect on operating surplus of these fluctuations, our partnership agreement will require that an amount equal to an estimate of the average quarterly maintenance capital expenditures necessary to maintain, including over the long term, our operating capacity, asset base or operating income will be subtracted from operating surplus each quarter, as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the board's conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our estimated maintenance capital expenditures, such as a major acquisition. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please see "Cash Distribution Policy and Restrictions on Distributions."

        The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

    it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

    it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

    it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

        Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity, asset base or operating income. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of additional pipeline or processing capacity, to the extent such capital expenditures are expected to increase our long-term

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operating capacity, asset base or operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction of such capital improvement and paid during the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the date any such capital improvement commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

        As described below, none of investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as gathering pipelines or processing facilities) paid during the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

        Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures.

        Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner, with the concurrence of the conflicts committee of our general partner.

    Capital Surplus

        Capital surplus generally consists of:

    borrowings other than working capital borrowings;

    sales of our equity and debt securities;

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;

    capital contributions received; and

    corporate reorganizations or restructurings.

    Characterization of Cash Distributions

        Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to $25 million, which does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

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Subordination Period

    General

        Our partnership agreement provides that, during the subordination period (which we define below and in Appendix B), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to herein as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

    Subordination Period

        The subordination period will extend until the first business day of any quarter beginning after December 31, 2010 that each of the following tests are met:

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

    the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest during those periods on a fully diluted basis during those periods; and

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

        Alternatively, the subordination period will end the first business day after the following tests are met:

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units and the corresponding distributions on the 2% general partner interest equaled or exceeded $0.50625 (150% of the minimum quarterly distribution) for each quarter for four consecutive non-overlapping quarters;

    the "adjusted operating surplus" (as defined below) generated during each of the four consecutive non-overlapping quarters immediately preceding the date equaled or exceeded $0.50625 (150% of the minimum quarterly distribution) on each of the outstanding common units, subordinated units and the corresponding distributions on the 2% general partner interest during those periods; and

    there are no arrearages in payment of the minimum quarterly distributions on the common units.

        When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of

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available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

    the subordination period will end and each subordinated unit will immediately convert into one common unit;

    any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

    our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or receive cash in exchange for those interests.

    Adjusted Operating Surplus

        Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:

    operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under "—Operating Surplus and Capital Surplus—Operating Surplus" above); less

    any net increase in working capital borrowings (including our proportionate share of any net increase of certain subsidiaries we do not wholly own, including Enogex) with respect to that period; less

    any net decrease in cash reserves for operating expenditures (including our proportionate share of any net decreases of certain subsidiaries we do not wholly own, including Enogex) with respect to that period not relating to an operating expenditure made with respect to that period; plus

    any net decrease in working capital borrowings (including our proportionate share of any net decrease of certain subsidiaries we do not wholly own, including Enogex) with respect to that period; plus

    any net increase in cash reserves for operating expenditures (including our proportionate share of any net increases of certain subsidiaries we do not wholly own, including Enogex) with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus During the Subordination Period

        Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

    first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

    second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

    third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

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    thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

        Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

    first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

        Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner's 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

        Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

        The following discussion assumes that our general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

        If for any quarter:

    we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

    we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among our unitholders and our general partner in the following manner:

    first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.3881 per unit for that quarter (the "first target distribution");

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    second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4219 per unit for that quarter (the "second target distribution");

    third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.50625 per unit for that quarter (the "third target distribution"); and

    thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

Percentage Allocations of Available Cash from Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between our unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

 
  Total Quarterly
Distribution Per Unit

  Marginal Percentage
Interest in Distributions

 
  Target
Amount

  Unitholders
  General Partner
Minimum Quarterly Distribution   $0.3375   98%   2%
First Target Distribution   up to $0.3881   98%   2%
Second Target Distribution   above $0.3881 up to $0.4219   85%   15%
Third Target Distribution   above $0.4219 up to $0.50625   75%   25%
Thereafter   above $0.50625   50%   50%

General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution

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payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during that period.

        The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (1) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive quarters ended immediately prior to the date of such reset election divided by (2) the average of the amount of cash distributed per common unit during each of those two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units.

        Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset election (such amount is referred to herein as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

    first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

    second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;

    third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for that quarter; and

    thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

        The following table illustrates the percentage allocation of available cash from operating surplus between our unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two quarters immediately preceding the reset election was $0.60.

 
   
  Marginal Percentage
Interest in Distributions

   
 
  Quarterly Distribution per
Unit Prior to Reset

  Unitholders
  General
Partner

  Quarterly Distribution per Unit
Following Hypothetical Reset

Minimum Quarterly Distribution   $0.3375   98%   2 % $0.6000
First Target Distribution   up to $0.3881   98%   2 % up to $0.6900(1)
Second Target Distribution   above $0.3881 up to $0.4219   85%   15 % above $0.6900 up to $0.7500(2)
Third Target Distribution   above $0.4219 up to $0.50625   75%   25 % above $0.7500 up to $0.9000(3)
Thereafter   above $0.50625   50%   50 % above $0.9000(3)

(1)
This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2)
This amount is 125% of the hypothetical reset minimum quarterly distribution.

(3)
This amount is 150% of the hypothetical reset minimum quarterly distribution.

82


        The following table illustrates the total amount of available cash from operating surplus that would be distributed to our unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that the underwriters exercise in full their option to purchase additional common units, that there are 25,783,428 common units and 526,192 unit equivalents representing the 2% general partner interest outstanding and that the average distribution to each common unit is $0.60 for each of the two quarters prior to the reset. The assumed number of outstanding units assumes the underwriters exercise in full their option to purchase additional common units, the conversion of all subordinated units into common units and no additional unit issuances.

 
   
   
  General Partner Cash Distributions Prior to Reset
   
 
   
  Common
Unitholders
Cash
Distributions
Prior to Reset

   
 
  Quarterly
Distribution Per Unit
Prior to Reset

  Class B
Units

  2%
General
Partner
Interest

  Incentive
Distribution
Rights

  Total
  Total
Distributions

Minimum Quarterly Distribution   $0.3375   $ 8,701,907   $   $ 177,590   $   $ 177,590   $ 8,879,497
First Target Distribution   up to $0.3881     1,304,642         26,625         26,625     1,331,267
Second Target Distribution   above $0.3881 up to $0.4219     871,480         20,505     133,285     153,790     1,025,270
Third Target Distribution   above $0.4219 up to $0.50625     2,176,121         58,030     667,344     725,374     2,901,495
Thereafter   above $0.50625     2,415,907         96,636     2,319,271     2,415,907     4,831,814
       
 
 
 
 
 
        $ 15,470,057   $   $ 379,386   $ 3,119,900   $ 3,499,286   $ 18,969,343
       
 
 
 
 
 

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to our unitholders and our general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 25,783,428 common units, 5,199,833 Class B units and 632,310 unit equivalents representing the 2% general partner interest outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (1) the $3,119,900 received by our general partner in respect of its incentive distribution rights per quarter for the two quarters prior to the reset as shown in the table above by (2) the $0.60 of available cash from operating surplus distributed to each common unit as the average distributed per common unit per quarter for each of the two quarters prior to the reset.

 
   
  Common
Unitholders
Cash
Distributions
After Reset

  General Partner Cash Distributions After Reset
   
 
  Quarterly
Distribution per
Unit
After Reset

   
 
  Class B
Units

  2% General
Partner
Interest

  Incentive
Distribution
Rights

  Total
  Total
Distributions

Minimum Quarterly Distribution   $0.6000   $ 15,470,057   $ 3,119,900   $ 379,386   $   $ 3,499,286   $ 18,969,343
First Target Distribution(1)   up to $0.6900                                    
Second Target Distribution(2)   above $0.6900 up to $0.7500                                    
Third Target Distribution(3)   above $0.7500 up to $0.9000                                    
Thereafter   above $0.9000                                    
       
 
 
 
 
 
        $ 15,470,057   $ 3,119,900   $ 379,386   $   $ 3,499,286   $ 18,969,343
       
 
 
 
 
 

(1)
This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2)
This amount is 125% of the hypothetical reset minimum quarterly distribution.

(3)
This amount is 150% of the hypothetical reset minimum quarterly distribution.

83


        Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

    How Distributions from Capital Surplus will be Made

        Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

    first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

    second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

    thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

        The preceding paragraph assumes that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

    Effect of a Distribution from Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to herein as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume our general partner maintains its 2% general partner interest and has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

    the minimum quarterly distribution;

    target distribution levels;

    the unrecovered initial unit price; and

    the number of common units into which a subordinated unit is convertible.

84


        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that our general partner may reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

    General

        If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

    Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

    first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

    second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

    third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

    fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target

85


      distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;

    fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

    sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and

    thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

        The percentage interests set forth above for our general partner include its 2% general partner interest and assume our general partner has not transferred the incentive distribution rights.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

    Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:

    first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

    second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

    thereafter, 100% to the general partner.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

    Adjustments to Capital Accounts

        Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

86



SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

        OGE Enogex Partners L.P. was formed on May 30, 2007 and does not have any historical consolidated financial statements prior to its formation. The following tables set forth, for the periods and at the dates indicated, the selected historical financial and operating data of Enogex Predecessor, which financial data is derived from the books and records of Enogex Predecessor, and the selected pro forma financial and operating data of OGE Enogex Partners L.P.

        The selected historical financial data for the years ended December 31, 2006, 2005 and 2004 and balance sheet data at December 31, 2006 and 2005 is derived from and should be read in conjunction with the audited historical consolidated financial statements of Enogex Predecessor included elsewhere in this prospectus beginning on page F-12. The selected historical financial data for the years ended December 31, 2003 and 2002 and at December 31, 2004, 2003 and 2002 is derived from the audited historical consolidated financial statements of Enogex Predecessor. The selected historical financial data for the nine months ended September 30, 2007 and 2006 and balance sheet data at September 30, 2007 is derived from and should be read in conjunction with the unaudited historical condensed consolidated financial statements of Enogex Predecessor included elsewhere in this prospectus beginning on page F-62. In each case, the selected historical financial and operating data reflects 100% of Enogex's operations, but following our formation transactions (and as reflected in the pro forma financial data), we will own only a 25% interest in Enogex. Also, in each case, the summary historical financial and operating data reflects Enogex's ownership of OERI, but following our formation transactions (and as reflected in the pro forma financial and operating data), Enogex will not own OERI. OERI's results of operations are included in the summary historical financial and operating data as, subsequent to the distribution of the stock of OERI to OGE Energy, it is anticipated that the ongoing transactions between OERI and Enogex will constitute a significant continuation of activities and cash flows for Enogex. The operating data for all periods is unaudited. The selected pro forma financial data is derived from and should be read in conjunction with the unaudited pro forma consolidated financial statements of OGE Enogex Partners L.P. included in this prospectus beginning on page F-2. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the balance sheet data, or as of January 1, 2006, in the case of the statements of income for the year ended December 31, 2006 and the nine months ended September 30, 2007. These transactions include:

    the distribution by Enogex of the shares of OERI to OGE Energy;

    the dividend by Enogex of outstanding advances to OERI to OGE Energy;

    the conversion of Enogex Inc. to a Delaware limited liability company;

    the conversion of outstanding intercompany loans from Enogex to OGE Energy to a dividend from Enogex to OGE Energy;

    our ownership of a 25% membership interest in Enogex;

    the issuance by us of common units to the public;

    the payment of underwriting discounts and commissions, the structuring fee and other offering expenses;

    the contribution by us of proceeds of this offering to Enogex;

    the redemption by Enogex of its $400 million 8.125% senior notes due 2010; and

    interest expense associated with short-term borrowings from OGE Energy incurred to pay a portion of the costs associated with the expected redemption of Enogex's $400 million 8.125% senior notes due 2010 and associated with borrowings under Enogex's new credit facility.

87


        The following tables include the financial measure of Adjusted EBITDA, which is a non-GAAP financial measure. We define Adjusted EBITDA as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see "Summary—Non-GAAP Financial Measures."

        The following table presents the selected historical financial and operating data of Enogex Predecessor and our selected pro forma financial and operating data for the periods indicated:

 
  Enogex Predecessor
  OGE Enogex Partners L.P.
 
 
  Year Ended
December 31,

  Nine Months Ended
September 30,

  Year Ended
December 31, 2006

  Nine Months Ended September 30, 2007
 
 
  2002
  2003
  2004
  2005
  2006
  2006
  2007
  Pro Forma(1)
  Pro Forma(1)
 
 
  (in millions, except per unit and operating data)

 
Results of Operations Data:                                                        
  Operating revenues   $ 1,652.0   $ 2,306.2   $ 3,372.2   $ 4,340.1   $ 2,367.8   $ 1,838.0   $ 1,509.3   $ 832.9   $ 659.0  
  Cost of goods sold     1,458.2     2,070.2     3,118.2     4,090.4     2,060.4     1,616.4     1,255.8     539.6     424.2  
   
 
 
 
 
 
 
 
 
 
  Gross margin on revenues     193.8     236.0     254.0     249.7     307.4     221.6     253.5     293.3     234.8  
  Other operation and maintenance(2)     97.2     87.4     93.5     96.6     110.0     80.3     88.4     103.0     85.8  
  Depreciation     45.8     40.9     41.1     40.4     42.3     31.2     33.9     42.1     33.8  
  Impairment of assets     48.3     9.2     7.8         0.3     0.3     0.5     0.3     0.5  
  Taxes other than income     14.6     16.4     16.0     15.4     16.0     12.6     12.0     15.5     11.5  
   
 
 
 
 
 
 
 
 
 
  Operating income (loss)     (12.1 )   82.1     95.6     97.3     138.8     97.2     118.7     132.4     103.2  
  Interest income     1.0     0.8     3.2     2.9     11.1     8.7     7.0     2.9     0.2  
  Other income     0.9     0.7     4.5     0.8     7.7     6.4     0.8     7.7     0.7  
  Other expense     0.2     1.6     0.3     0.3     0.3     0.2     0.2     0.3     0.2  
  Interest expense(3)     43.9     34.1     32.2     32.6     31.8     23.8     24.2     24.6     18.6  
  Income tax expense (benefit)     (20.6 )   19.8     26.4     23.4     48.0     33.9     39.3          
   
 
 
 
 
 
 
 
 
 
  Income (loss) from continuing operations     (33.7 )   28.1     44.4     44.7     77.5     54.4     62.8     118.1     85.3  
  Income from discontinued operations(4)     12.1     4.7     11.6     49.8     36.0     36.0              
  Cumulative effect of change in accounting principle         (5.9 )                            
   
 
 
 
 
 
 
 
 
 
  Income (loss) before non- controlling interest     (21.6 )   26.9     56.0     94.5     113.5     90.4     62.8     118.1     85.3  
  Non-controlling interest(5)                                 (89.5 )   (64.7 )
   
 
 
 
 
 
 
 
 
 
  Net income (loss)   $ (21.6 ) $ 26.9   $ 56.0   $ 94.5   $ 113.5   $ 90.4   $ 62.8   $ 28.6   $ 20.6  
   
 
 
 
 
 
 
 
 
 
  General partner's interest in net income                                             $ 0.6   $ 0.4  
                                             
 
 
  Limited partners' interest in net income                                             $ 28.0   $ 20.2  
                                             
 
 
  Number of outstanding common units                                               12.3     12.3  
  Number of outstanding subordinated units                                               12.3     12.3  
  Basic and diluted earnings per common unit                                             $ 1.14   $ 0.82  
  Basic and diluted earnings per subordinated unit                                             $ 1.14   $ 0.82  

88


 
  Enogex Predecessor
  OGE Enogex Partners L.P.
 
  Year Ended
December 31,

  Nine Months Ended
September 30,

  Year Ended
December 31, 2006

  Nine Months Ended September 30, 2007
 
  2002
  2003
  2004
  2005
  2006
  2006
  2007
  Pro Forma(1)
  Pro Forma(1)
 
  (in millions, except per unit and operating data)

Balance Sheet Data (at period end):                                                      
  Property, plant and equipment, net(6)   $ 1,137.4   $ 1,043.2   $ 1,016.5   $ 875.9   $ 865.7   $ 859.9   $ 927.0         $ 926.5
  Total assets     1,532.6     1,554.5     1,719.7     1,652.6     1,319.8     1,336.0     1,237.8           1,024.0
  Long-term debt     591.4     522.7     477.8     407.6     403.7     404.0     402.0           313.9
  Net owner's equity     429.6     449.8     491.0     440.4     400.0     399.7     380.3           181.9
Other Financial Data:                                                      
  Net cash flows provided by (used in):                                                      
    Operating activities   $ 60.8   $ 10.6   $ 118.2   $ 235.2   $ 131.6   $ 73.8   $ 69.0            
    Investing activities     (20.3 )   (25.9 )   (22.5 )   (34.5 )   (65.1 )   (49.1 )   (96.3 )          
    Financing activities     (97.5 )   (27.0 )   (118.6 )   (304.0 )   (139.4 )   (20.9 )   29.2            
  Adjusted EBITDA(7)                 140.9     138.2     188.5     134.6     153.2   $ 181.9     137.5
Operating Data (excludes discontinued operations):                                                      
  New well connects(8)                     362     276     295     362     295
  New well connects(9)     166     200     192     223     206     154     137     206     137
  Gathered volumes—TBtu/d     1.00     0.95     0.84     0.92     0.98     0.97     1.04     0.98     1.04
  Incremental transportation volumes—TBtu/d(10)     0.38     0.36     0.39     0.39     0.46     0.48     0.48     0.46     0.48
  Total throughput volumes—
TBtu/d
    1.38     1.31     1.23     1.31     1.44     1.45     1.52     1.44     1.52
  Natural gas processed—TBtu/d     0.45     0.41     0.50     0.52     0.54     0.53     0.56     0.54     0.56
  Natural gas liquids sold (keep- whole)—million gallons     269     207     185     191     244     181     178     244     178
  Natural gas liquids sold (purchased for resale)—million gallons             78     96     113     76     83     113     83
  Natural gas liquids sold (percent- of-liquids)—million gallons     22     18     16     15     14     10     12     14     12
  Total natural gas liquids sold—million gallons     291     225     279     302     371     267     273     371     273
  Average sales price per gallon   $ 0.406   $ 0.595   $ 0.720   $ 0.873   $ 0.901   $ 0.914   $ 0.982   $ 0.901   $ 0.982

(1)
The pro forma data for the year ended December 31, 2006 and the nine months ended September 30, 2007 reflects the distribution of the stock of OERI to OGE Energy.

(2)
The pro forma financial data for the year ended December 31, 2006 and the nine months ended September 30, 2007 include expenses of the partnership incurred as a result of being a publicly traded partnership of $1.1 million and $1.1 million, respectively. These partnership expenses are not expenses of Enogex and, therefore, are added back to income before non-controlling interest prior to calculating the non-controlling interest.

(3)
Under the provisions of Enogex's $400 million 8.125% senior notes due 2010 currently expected to be redeemed in connection with this offering, Enogex will pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million in connection with that redemption. As these items do not have a continuing impact, no adjustments for these items are provided in the accompanying unaudited pro forma consolidated statements of income.

(4)
Amounts for 2005 and 2004 were restated for discontinued operations related to the sale of Enogex assets in May 2006, as discussed in Note 6 of Notes to Consolidated Financial Statements. Amounts for years 2003 and 2002 have not been restated for discontinued operations since this information is not available as Enogex Predecessor's financial records were not maintained in a manner to provide this information for years prior to 2004.

(5)
Represents OGE Energy's 75% ownership interest in Enogex.

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(6)
Includes net property, plant and equipment related to discontinued operations of approximately $180.7 million, $166.9 million, $169.3 million and $34.9 million during the years ended December 31, 2002, 2003, 2004 and 2005, respectively.

(7)
We define Adjusted EBITDA as net income from continuing operations before non-controlling interest, interest, income taxes and depreciation. Adjusted EBITDA is used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and others, to assess:

the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis;

Enogex's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

    The economic substance behind the use of Adjusted EBITDA is to measure the ability of Enogex's assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to its members.

    The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income from continuing operations. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income from continuing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

    To compensate for the limitations of Adjusted EBITDA as an analytical tool, we believe it is important to review the comparable GAAP measures and understand the differences between the measures.

(8)
Includes wells behind central receipt points (as reported to us by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site. This information is not available for years prior to 2006 as Enogex Predecessor's books and records were not maintained in a manner to provide this information for years prior to 2006.

(9)
Excludes wells behind central receipt points.

(10)
Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The historical financial statements included in this prospectus reflect the assets, liabilities and operations of Enogex Predecessor. The following discussion analyzes the financial condition and results of operations of Enogex Predecessor, which reflects ownership of 100% of the assets of Enogex, as well as the ownership of OGE Energy Resources, or OERI, but following the transactions discussed herein, including the distribution by Enogex of the stock of OERI to OGE Energy, the contribution of a membership interest in Enogex by OGE Energy and the contribution of offering proceeds by us to Enogex, we will own only a 25% interest in the assets of Enogex and OGE Energy will retain the remaining 75% interest and Enogex will no longer own OERI. You should read the following discussion of the financial condition and results of operations for Enogex Predecessor in conjunction with the audited historical consolidated financial statements and accompanying notes of Enogex Predecessor and the unaudited pro forma consolidated financial statements and accompanying notes for OGE Enogex Partners L.P. included elsewhere in this prospectus.

        All references in this Management's Discussion and Analysis of Financial Condition and Results of Operations to our, we, and us refer to OGE Enogex Partners L.P. and its subsidiaries, including its interest in Enogex LLC, after giving effect to the formation transactions described herein, including the conversion of Enogex Inc. to Enogex LLC, a Delaware limited liability company. All references in this Management's Discussion and Analysis of Financial Condition and Results of Operations to Enogex Predecessor or to Enogex when used in a historical context refer to Enogex Inc. and its subsidiaries. All references in this Management's Discussion and Analysis of Financial Condition and Results of Operations to Enogex when used in the present tense or prospectively refer to Enogex LLC and its subsidiaries, collectively, or to Enogex LLC individually, as the context may require.

Our Business

        We are a provider of integrated natural gas midstream services. We were formed by OGE Energy to further develop its natural gas midstream assets and operations. OGE Energy is the parent company of OG&E, a regulated electric utility, and Enogex Inc., an integrated natural gas midstream services provider. In connection with this offering, Enogex Inc. will convert to Enogex LLC, a Delaware limited liability company. Upon the completion of this offering, a wholly owned subsidiary of OGE Energy will own a 68.2% limited partner interest in us and a 2% general partner interest in us through its ownership of OGE Enogex GP LLC, our general partner. Our wholly owned subsidiary will own a 25% membership interest in Enogex and will be its managing member, and our general partner, on our and our wholly owned subsidiary's behalf, will control the assets and operations of Enogex. A wholly owned subsidiary of OGE Energy will own the remaining 75% membership interest in Enogex and will be a non-managing member. Upon the completion of this offering, our interest in Enogex will be our only cash-generating asset.

Operations

        Enogex's ongoing operations will be organized into two businesses: (1) natural gas transportation and storage and (2) natural gas gathering and processing.

    Transportation and Storage.    Enogex owns and operates approximately 2,283 miles of intrastate natural gas transportation pipelines with approximately 1.52 TBtu/d of average daily throughput for the nine months ended September 30, 2007. Enogex's transportation pipelines are directly connected to 11 third-party natural gas pipelines at 64 interconnect points and to 27 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma. Enogex provides fee-based intrastate transportation services on a firm and interruptible basis and interstate transportation services pursuant to Section 311 of the NGPA on an interruptible basis

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      only. Enogex owns and operates two natural gas storage facilities, the Wetumka Storage Facility and the Stuart Storage Facility, with approximately 23 Bcf of aggregate working gas capacity. The storage facilities have approximately 650 MMcf/d, of maximum withdrawal capacity and approximately 650 MMcf/d of injection capacity. Enogex provides fee-based firm and interruptible storage services to third parties at market-based rates.

    Gathering and Processing.    Enogex owns and operates approximately 5,474 miles of natural gas gathering pipelines with approximately 1.04 TBtu/d of average daily throughput for the nine months ended September 30, 2007. Enogex also owns and operates six natural gas processing plants with approximately 720 MMcf/d of aggregate inlet capacity and has a 50% ownership interest in and operates an additional natural gas processing plant with approximately 20 MMcf/d of inlet capacity. Enogex provides well connect, gathering, measurement, treating, dehydration, compression and processing services to its producer customers primarily in the Arkoma and Anadarko basins, including those operating in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma. For the year ended December 31, 2006, Enogex processed approximately 0.54 TBtu/d of natural gas and extracted and sold approximately 371 million gallons of natural gas liquids, or NGLs.

        Historically, Enogex had also engaged in natural gas marketing through OERI. In connection with this offering, on January 1, 2008, Enogex distributed the stock of OERI to OGE Energy. Accordingly, immediately following the offering, Enogex's operations will no longer include the marketing of natural gas.

Factors That Significantly Affect Our and Enogex's Results

    Transportation and Storage

        Results of operations from the transportation and storage business are determined primarily by the volumes of natural gas transported on Enogex's intrastate pipeline system, volumes of natural gas stored at Enogex's storage facilities and the level of fees charged to Enogex's customers for such services. Enogex generates a majority of its revenues and margins for its pipeline business under fee-based transportation contracts that are directly related to the volume of natural gas capacity reserved on its system. The margin Enogex earns from its transportation activities is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, Enogex's revenues from these arrangements would be reduced.

        Generally, Enogex provides to shippers two types of fee-based transportation services under its intrastate transportation contracts:

    Firm Transportation.    Enogex's obligation to provide firm transportation service means that it is obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on Enogex's part, the shipper pays a specified demand or reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a transportation or commodity charge with respect to quantities actually transported by Enogex.

    Interruptible Transportation.    Enogex's obligation to provide interruptible transportation service means that it is only obligated to transport natural gas nominated by the shipper to the extent that it has available capacity. For this service, the shipper pays no demand or reservation charge but pays a transportation or commodity charge for quantities actually shipped.

Enogex also provides interstate transportation services on an interruptible basis pursuant to Section 311 of the NGPA at rates approved by the FERC.

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        Enogex offers both fee-based firm and interruptible storage services to third parties. Services offered under Section 311 of the NGPA are pursuant to the terms and conditions specified in Enogex's Statement of Operating Conditions for gas storage and at market-based rates negotiated with each customer. Enogex's customers include end-users, local distribution companies, producers and marketers, which contract for a majority of Enogex's storage services. Factors that impact Enogex's storage margins include, among other things, changes in the price or availability of natural gas or other forms of energy, seasonal and locational (basis) spreads, hourly load swings for power generators, weather, avoidance of costly imbalances and overrun penalties.

        Two key contracts for Enogex's transportation and storage business are its contracts with OG&E, the largest electric utility in Oklahoma which serves the Oklahoma City market, and PSO, the second largest utility in Oklahoma, serving the Tulsa market. As part of the no-notice load following contract with OG&E, Enogex provides natural gas storage services for OG&E. Enogex has been providing natural gas storage services to OG&E since August 2002 when it acquired the Stuart Storage Facility. Enogex provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract, which expires January 1, 2013, and the OG&E contract, which expires April 30, 2009, provide for a monthly demand charge plus variable transportation charges (including fuel). During 2004, 2005, 2006 and the first nine months of 2007, revenues from Enogex's firm intrastate transportation and storage contracts were approximately $95.6 million, $95.0 million, $98.1 million and $79.3 million, respectively, of which $49.6 million, $47.6 million, $47.6 million and $35.5 million was attributed to OG&E and $13.3 million, $13.3 million, $13.3 million and $10.8 million, respectively, was attributed to PSO.

    Gathering and Processing

        Results of operations from the gathering and processing business are determined primarily by the volumes of natural gas Enogex gathers and processes, its current contract portfolio and natural gas and NGL prices.

        Because of the natural decline in production from existing wells connected to Enogex's systems, Enogex's success depends on its ability to gather new sources of natural gas, which depends on certain factors beyond its or our control. Any decrease in supplies of natural gas could adversely affect Enogex's gathering and processing business. As a result, Enogex's cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on its gathering systems and the asset utilization rates at its natural gas processing plants, Enogex must continually obtain new natural gas supplies. The primary factors affecting Enogex's ability to obtain new supplies of natural gas and attract new customers to its assets depends in part on the level of successful drilling activity near these systems, Enogex's ability to compete for volumes from successful new wells and Enogex's ability to expand capacity as needed.

        Neither we nor Enogex have control over the level of drilling activity in the areas of Enogex's operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. The primary factor that impacts drilling decisions is natural gas prices. Natural gas prices reached relatively high levels in late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by Enogex's gathering, processing and transportation facilities, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers' capital budgets, the ability of producers to obtain necessary drilling and other governmental permits, costs of steel and other commodities, geological considerations, demand for hydrocarbons, the level of reserves, other production and development costs and regulatory changes.

        Enogex gathers and processes natural gas pursuant to a variety of arrangements generally categorized as "fee-based" arrangements, "percent-of-proceeds" and "percent-of-liquids" arrangements and "keep-whole" arrangements. Under fee-based arrangements, Enogex earns cash fees for the services that it renders. Under the latter types of arrangements, Enogex generally purchases raw natural gas and sells processed natural gas and NGLs or receives NGLs.

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        Percent-of-proceeds, percent-of-liquids and keep-whole arrangements involve commodity price risk to Enogex because Enogex's margin is based in part on natural gas and NGL prices. Enogex seeks to minimize its exposure to fluctuations in commodity prices in several ways, including managing its contract portfolio. In managing its contract portfolio, Enogex classifies its gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.

    Fee-Based Arrangements.    Under these arrangements, Enogex generally is paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through Enogex's system and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in Enogex's fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At September 30, 2007, these arrangements accounted for approximately 7% of Enogex's natural gas processed volumes.

    Percent-of-Proceeds and Percent-of-Liquids Arrangements.    Under these arrangements, Enogex generally gathers raw natural gas from producers at the wellhead, transports the gas through its gathering system, processes the gas and sells the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which Enogex shares in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which Enogex receives proceeds from the sale of NGLs or the NGLs themselves as compensation for its processing services as percent-of-liquids arrangements. Under percent-of-proceeds arrangements, Enogex's margin correlates directly with the prices of natural gas and NGLs. Under percent-of-liquids arrangements, Enogex's margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component). At September 30, 2007, these arrangements accounted for approximately 24% of Enogex's natural gas processed volumes.

    Keep-Whole Arrangements.    Under these arrangements, Enogex processes raw natural gas to extract NGLs and pays to the producer the full gas equivalent Btu value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. Enogex is generally entitled to retain the processed NGLs and to sell them for its own account. Accordingly, Enogex's margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of Enogex's keep-whole contracts include provisions that reduce its commodity price exposure, including (1) conditioning floors (such as the default processing fee described below) that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their gas equivalent Btu value in natural gas, (2) embedded discounts to the applicable natural gas index price under which Enogex may reimburse the producer an amount in cash for the gas equivalent Btu value of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing. At September 30, 2007, these arrangements accounted for approximately 69% of Enogex's natural gas processed volumes.

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        In addition, as a seller of NGLs, Enogex is exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, in 2002, Enogex revised its Statement of Operating Conditions used as part of its typical natural gas processing arrangements and included language that requires a "default processing fee" in the event the gathered gas exceeds downstream interconnect specifications. Natural gas that is greater than 1,080 Btu per cubic foot coming out of wells must typically be processed before it can enter an interstate pipeline. The default processing fee stipulates a minimum fee to be paid to the processor if the market for NGLs is lower than the gas equivalent Btu value of the natural gas that is removed from the stream. The default processing fee helps to minimize the risk of processing gas that is greater than 1,080 Btu per cubic foot when the price of the NGLs to be extracted and sold is less than the Btu value of the natural gas that Enogex otherwise would be required to replace.

        Additionally, Enogex has instituted a hedging program that is intended to reduce the commodity price risk associated with Enogex's keep-whole and percent-of-liquids arrangements. Enogex intends to hedge approximately 70% of its NGL volumes when market conditions dictate. As of December 31, 2007, Enogex had hedged approximately 63% of its expected non-ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008, 2009 and 2010. As of December 31, 2007, Enogex had hedged approximately 41% of its expected ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008. Enogex has the option to reject ethane if processing it is not economical. Enogex used a combination of forward sales, purchased put options and swaps in its hedging program. The default processing fee, coupled with Enogex's hedge program, is expected to reduce the risk of commodity price volatility. Where market conditions permit, Enogex intends to pursue the conversion of existing keep-whole contracts to fixed fee-based arrangements. Enogex continually monitors its hedging and contract portfolio and expects to continue to adjust its hedge position as conditions warrant.

        Enogex relies on certain key natural gas producer customers for a significant portion of its natural gas and NGL supply. During 2006, Enogex's top five natural gas producer customers were Chesapeake Energy Marketing Inc., Apache Corporation, Scissortail Energy, LLC, Samson Resources Company and Burlington Resources Trading Inc., and they accounted for approximately 18.7%, 15.2%, 9.2%, 4.2% and 3.3%, respectively, of Enogex's natural gas and NGL supply. During the first nine months of 2007, Enogex's top five natural gas producer customers were Chesapeake Energy Marketing Inc., Apache Corporation, Scissortail Energy, LLC, Devon Gas Services, L.P. and Samson Resources Company, and they accounted for approximately 18.7%, 16.4%, 8.4%, 4.2% and 3.7%, respectively, of Enogex's natural gas and NGL supply. Should Enogex lose the natural gas and NGL volumes supplied by any of these customers, Enogex would seek new or incremental volumes from other parties to utilize the resulting capacity. The loss of the natural gas and NGL volumes supplied by these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on our and Enogex's business, results of operations, financial condition and cash available for distribution.

        In May 2006, Enogex's gathering business sold certain gas gathering assets in the Kinta, Oklahoma area, which have been reported as discontinued operations in Enogex's consolidated financial statements. Please see "—Results of Operations—Discontinued Operations" below for a further discussion.

General Trends and Outlook

        We expect Enogex's business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be

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incorrect, our and Enogex's actual results may vary materially from our and its expected results. Please see "Risk Factors."

    Natural Gas Supply and Demand Outlook

        Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, natural gas consumption in the United States is expected to grow from approximately 60.2 Bcf/d in 2005 to approximately 70.1 Bcf/d in 2017, or by approximately 1.3% per year. During the five years ended December 31, 2006, the United States on average consumed approximately 22.3 trillion cubic feet, or Tcf, per year, while total marketed domestic production averaged approximately 19.5 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

        Based on projections from the EIA and experience with Enogex's producer customers, we believe that current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. According to the EIA, although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe, based on our recent experience, that this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe that an increase in U.S. natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.

        Many of the areas in which Enogex operates are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in substantially all of the areas in which Enogex operates, fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. Neither we nor Enogex have control over the level of natural gas exploration and development activity in the areas of Enogex's operations.

    Commodity Prices

        As discussed above, our revenues and margins generally improve in an environment of high natural gas and NGL prices. Our gathering and processing margins, in particular, generally improve when NGL prices are high relative to the price of natural gas. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. With respect to natural gas, the mid-continent prices for natural gas, as represented by the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract in 2006 ranged from a high of $8.76 per million British thermal unit, or MMBtu, to a low of $3.54 per MMBtu. In 2007, the same index ranged from a high of $6.82 per MMBtu to a low of $4.73 per MMBtu. Natural gas prices reached relatively high levels in late 2005 due to the impact of Hurricanes Katrina and Rita but have returned to the near $6.00 per MMBtu level experienced over most of the period since 2004. With respect to NGLs, the mid-continent prices for propane, for example, as represented by the average of the Oil Price Information Service daily average posting at the Conway, Kansas market, in 2006 ranged from a high of $1.14 per gallon to a low of $0.90 per gallon. In 2007, the same index ranged from a high of $1.52 per gallon to a low of $0.87 per gallon.

        Our and Enogex's revenue and cash flows may be materially adversely affected if the midstream industry experiences significant, prolonged deterioration below general price levels experienced in recent years.

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        The markets and prices for natural gas and NGLs depend upon factors beyond our and Enogex's control. These factors are discussed above under "Risk Factors—Risks Related to Our Business—Some factors that affect prices of natural gas and NGLs are beyond our control and changes in these prices could adversely affect our and Enogex's revenue and cash available for distribution."

        Enogex's percent-of-proceeds and percent-of-liquids natural gas processing arrangements constituted approximately 6% of its gross margin and accounted for approximately 24% of its natural gas processed volumes during the first nine months of 2007, compared to approximately 4% of its gross margin and approximately 19% of its natural gas processed volumes in 2006. Enogex's keep-whole natural gas processing arrangements constituted approximately 18% of its gross margin and accounted for approximately 69% of its natural gas processed volumes during the first nine months of 2007, compared to approximately 23% of its gross margin and approximately 73% of its natural gas processed volumes in 2006. These arrangements expose Enogex to risks associated with the price of natural gas and NGLs. Please see "Risk Factors—Risks Related to Our Business—Enogex's "keep-whole" natural gas processing arrangements and "percent-of-proceeds" and "percent-of-liquids" natural gas processing agreements expose it to risks associated with fluctuations associated with the price of natural gas and NGLs, which could adversely affect our and Enogex's revenue and cash available for distribution."

        At any given time, Enogex's overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that Enogex was a net buyer of natural gas) and a net long position in NGLs (meaning that Enogex was a net seller of NGLs). As a result, Enogex's margins could be negatively impacted to the extent the price of NGLs decreases in relation to the price of natural gas.

    Gathering and Processing Margins

        As of September 30, 2007, Enogex's overall portfolio of processing contracts reflected a net short position in natural gas of approximately 49,597 MMBtu/d (meaning that Enogex was a net buyer of natural gas) and a net long position in NGLs of approximately 16,571 barrels per day (meaning that Enogex was a net seller of NGLs). As a result, Enogex margins would be positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and would be adversely impacted to the extent the price of NGLs declined in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. This portfolio performed well in response to favorable fractionation spreads during the nine months ended September 30, 2007. Enogex has instituted a hedging program that is intended to reduce the commodity price risk associated with Enogex's keep-whole and percent-of-liquids arrangements. Enogex intends to hedge approximately 70% of its NGL volumes when market conditions dictate. As of December 31, 2007, Enogex had hedged approximately 63% of its expected non-ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008, 2009 and 2010. As of December 31, 2007, Enogex had hedged approximately 41% of its expected ethane NGL volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2008. Enogex has the option to reject ethane if processing it is not economical. For periods after 2010, management will evaluate whether to enter into any new hedging arrangements, and there can be no assurance that Enogex will enter into any new hedging arrangements.

    Impact of Interest Rates and Inflation

        Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our and Enogex's financing costs to increase accordingly. Although this could limit our and Enogex's ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

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        Inflation in the United States has been relatively low in recent years and did not have a material impact on Enogex's results of operations in 2006. Yet, the current high levels of natural gas exploration, development and production activities, both in the Arkoma and Anadarko basins and more broadly across the United States, is increasing competition for personnel and equipment. This increased competition is placing upward pressure on the prices Enogex pays for labor, supplies, property, plant and equipment. Enogex attempts to recover increased costs from its customers. To the extent Enogex is unable to procure necessary supplies or recover higher costs, our and Enogex's operating results will be negatively impacted.

Factors Affecting Comparability of Future Results

        You should read the discussion of Enogex's financial condition and results of operations in conjunction with Enogex's historical and our pro forma financial statements included elsewhere in this prospectus. Our future results could differ materially from Enogex's historical results due to a variety of factors, including the following:

    Partial Ownership of Operating Assets

        After this offering, our wholly owned subsidiary will own a 25% membership interest in Enogex and a wholly owned subsidiary of OGE Energy will own the remaining 75% membership interest. Enogex's historical consolidated financial statements were prepared from Enogex Predecessor's books and records related to Enogex's operating assets. Accordingly, the discussion that follows includes 100% of the results of operations for Enogex's operating assets, but following this offering we will have only a 25% interest in those results.

    Distribution of OERI

        In connection with this offering, on January 1, 2008, Enogex distributed the stock of OERI, its natural gas marketing subsidiary, to OGE Energy. Enogex's historical consolidated financial statements were prepared from Enogex Predecessor's books and records related to Enogex's operating assets. Accordingly, the discussion that follows includes the results of OERI, but following this offering Enogex will not have any interest in the results of OERI.

        Enogex has historically utilized, and is expected to continue to utilize, OERI for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2004, 2005 and 2006 and the nine months ended September 30, 2007, OERI recorded revenues from Enogex of approximately $98.3 million, $160.6 million, $107.1 million and $71.9 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2004, 2005 and 2006 and the nine months ended September 30, 2007, Enogex recorded revenues from OERI of approximately $299.5 million, $330.5 million, $291.9 million and $222.9 million, respectively, for the sale, at market rates, of natural gas. For 2007, OERI charged a fee to Enogex of approximately $3.3 million for providing these services, including approximately $2.5 million charged to Enogex during the nine months ended September 30, 2007. Enogex expects to continue to pay OERI certain fees for such services, which fees likely will exceed the fees paid historically and may increase over time. For instance, the fee that OERI will charge to Enogex in 2008 is expected to be approximately $5.2 million, which will include costs for credit support. To the extent those costs increase, the fee will also increase. For additional information regarding these services and fees, please see "Certain Relationships and Related Party Transactions—Contracts with Affiliates—Marketing and Administrative Services Agreement with OERI."

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    Additional General and Administrative Expenses

        We expect to incur approximately $2.1 million in incremental general and administrative expenses as a result of becoming a publicly traded entity. These costs include fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services, independent director compensation, additional finance and governance personnel and governance expense. These costs, of which $1.1 million will be incurred by us and $1.0 million will be incurred by Enogex, also include estimated amounts payable to OGE Energy and its affiliates in connection with the omnibus agreement. For additional information regarding these administrative services, please see "Certain Relationships and Related Party Transactions—Omnibus Agreement."

    Elimination of Tax Expenses as a Result of Converting to a Limited Liability Company

        In connection with this offering, Enogex will convert to a limited liability company that will be treated as a partnership for tax purposes. Accordingly, Enogex will not be subject to corporate income taxes. Moreover, because we are a partnership, we are also not subject to corporate income taxes. Therefore, after this offering, our tax expenses should decrease from the levels experienced by Enogex historically. For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please see "Material Tax Consequences."

How We Evaluate Our and Enogex's Operations

        Management uses a variety of financial and operational measurements to analyze our and Enogex's performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. The operating measurement used by management is volumes, and the financial measurements are gross margin on revenues (which is revenues minus cost of goods sold and is referred to herein as gross margin), operating income and other operation and maintenance expenses, each as reported in Enogex's consolidated financial statements.

    Volumes.    Enogex must continually obtain new supplies of natural gas to maintain or increase throughput volumes on its transportation and storage and gathering and processing systems. Enogex's ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas in which Enogex currently operates, (2) Enogex's ability to compete for volumes from successful new wells in other areas and (3) Enogex's ability to obtain natural gas that has been released from other commitments. To increase throughput volumes on its intrastate pipelines of its transportation and storage business, Enogex must contract with shippers, including producers and marketers, for supplies of natural gas. Enogex routinely monitors producer activity in the areas served by its gathering and intrastate transportation systems to pursue new supply opportunities. See "Business—Business Strategies—Expanding Enogex's operations through organic growth projects" for a description of significant opportunities currently being pursued by Enogex to increase the throughput volumes of its gathering and intrastate transportation systems.

    Gross margin.    We evaluate Enogex's consolidated and business segment performance based on gross margin as reported in Enogex's consolidated financial statements. We believe that it (either in total or by individual business segment) is an important performance measure of the core profitability of Enogex's operations. Senior management uses gross margin by business segment as the primary measure in deciding to allocate capital resources among the business segments.

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    Operating income.    We also evaluate consolidated performance and, to a lesser extent, business segment performance, based on operating income as reported in the accompanying consolidated financial statements. This measure (which consists of gross margin less other operation and maintenance expenses, depreciation, impairment of assets and taxes other than income) is part of our monthly financial reports and indicates Enogex's ongoing profitability, excluding the cost of capital and income taxes. In our judgment, this measure is more useful at the consolidated level because operating income at the business segment level often is significantly affected by allocations among the business segments of other operation and maintenance expenses. See Note 1 of Notes to Consolidated Financial Statements for a further discussion.

    Other operation and maintenance expenses.    Other operation and maintenance expenses are a separate measure that we use to evaluate performance of Enogex's field operations. Direct labor, insurance, property taxes, repairs and maintenance, utilities and contract services comprise the most significant portion of this item. These expenses are largely independent of the volumes through Enogex's systems but fluctuate depending on the activities performed during a specific period.

Results of Operations

        The following discussion and analysis presents factors that affected Enogex's consolidated results of operations for the nine months ended September 30, 2007 and 2006 and the years ended December 31, 2006, 2005 and 2004 and Enogex's consolidated financial condition at September 30, 2007 and December 31, 2006. The following information should be read in conjunction with the consolidated financial statements and notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

        The following tables compare Enogex's operating results by reportable business segment for the nine months ended September 30, 2007 and 2006 and the years ended December 31, 2006, 2005 and 2004.

Nine Months Ended September 30, 2007

  Transportation
and
Storage

  Gathering and Processing
  Marketing
  Eliminations
  Total
 
  (in millions)

Operating revenues   $ 179.3   $ 555.2   $ 1,149.5   $ (374.7 ) $ 1,509.3
Cost of goods sold     71.3     428.4     1,130.8     (374.7 )   1,255.8
   
 
 
 
 
Gross margin on revenues     108.0     126.8     18.7         253.5
Other operation and maintenance     33.0     50.9     4.5         88.4
Depreciation     12.9     20.9     0.1         33.9
Impairment of assets     0.5                 0.5
Taxes other than income     8.9     2.7     0.4         12.0
   
 
 
 
 
Operating income   $ 52.7   $ 52.3   $ 13.7   $   $ 118.7
   
 
 
 
 

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Nine Months Ended September 30, 2006

  Transportation
and
Storage

  Gathering and Processing
  Marketing
  Eliminations
  Total
 
  (in millions)

Operating revenues   $ 176.1   $ 520.7   $ 1,530.8   $ (389.6 ) $ 1,838.0
Cost of goods sold     83.1     398.7     1,524.2     (389.6 )   1,616.4
   
 
 
 
 
Gross margin on revenues     93.0     122.0     6.6         221.6
Other operation and maintenance     29.0     44.1     7.2         80.3
Depreciation     13.4     17.7     0.1         31.2
Impairment of assets         0.3             0.3
Taxes other than income     8.9     3.3     0.4         12.6
   
 
 
 
 
Operating income (loss)   $ 41.7   $ 56.6   $ (1.1 ) $   $ 97.2
   
 
 
 
 
Year Ended December 31, 2006

  Transportation
and
Storage

  Gathering and Processing
  Marketing
  Eliminations
  Total
 
  (in millions)

Operating revenues   $ 225.9   $ 704.3   $ 1,941.3   $ (503.7 ) $ 2,367.8
Cost of goods sold     100.3     536.7     1,927.1     (503.7 )   2,060.4
   
 
 
 
 
Gross margin on revenues     125.6     167.6     14.2         307.4
Other operation and maintenance     41.2     59.5     9.3         110.0
Depreciation     17.9     24.2     0.2         42.3
Impairment of assets         0.3             0.3
Taxes other than income     11.8     3.8     0.4         16.0
   
 
 
 
 
Operating income   $ 54.7   $ 79.8   $ 4.3   $   $ 138.8
   
 
 
 
 
Year Ended December 31, 2005

  Transportation
and
Storage

  Gathering and Processing
  Marketing
  Eliminations
  Total
 
  (in millions)

Operating revenues   $ 246.4   $ 644.5   $ 4,003.0   $ (553.8 ) $ 4,340.1
Cost of goods sold     147.3     504.3     3,992.6     (553.8 )   4,090.4
   
 
 
 
 
Gross margin on revenues     99.1     140.2     10.4         249.7
Other operation and maintenance     32.9     55.3     8.4         96.6
Depreciation     17.3     23.0     0.1         40.4
Taxes other than income     11.6     3.4     0.4         15.4
   
 
 
 
 
Operating income   $ 37.3   $ 58.5   $ 1.5   $   $ 97.3
   
 
 
 
 
Year Ended December 31, 2004

  Transportation
and
Storage

  Gathering and Processing
  Marketing
  Eliminations
  Total
 
  (in millions)

Operating revenues   $ 249.4   $ 524.7   $ 3,048.4   $ (450.3 ) $ 3,372.2
Cost of goods sold     134.9     401.3     3,032.3     (450.3 )   3,118.2
   
 
 
 
 
Gross margin on revenues     114.5     123.4     16.1         254.0
Other operation and maintenance     29.9     51.3     12.3         93.5
Depreciation     17.1     22.6     1.4         41.1
Impairment of assets     8.8     (1.0 )           7.8
Taxes other than income     11.6     3.8     0.6         16.0
   
 
 
 
 
Operating income   $ 47.1   $ 46.7   $ 1.8   $   $ 95.6
   
 
 
 
 

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    Operating Data—Continuing Operations

 
  Nine Months Ended
September 30,

 
  2007
  2006
New well connects (includes wells behind central receipt points)(A)     295     276
New well connects (excludes wells behind central receipt points)     137     154
Gathered volumes—TBtu/d     1.04     0.97
Incremental transportation volumes—TBtu/d(B)     0.48     0.48
   
 
  Total throughput volumes—TBtu/d     1.52     1.45
   
 
Natural gas processed—TBtu/d     0.56     0.53
Natural gas liquids sold (keep-whole)—million gallons     178     181
Natural gas liquids sold (purchased for resale)—million gallons     83     76
Natural gas liquids sold (percent-of-liquids)—million gallons     12     10
   
 
  Total natural gas liquids sold—million gallons     273     267
   
 
Average sales price per gallon   $ 0.982   $ 0.914

(A)
Includes wells behind central receipt points (as reported to management by third parties).

(B)
Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.

 
  Year ended December 31,
 
  2006
  2005
  2004
New well connects (includes wells behind central receipt points)(A)     362        
New well connects (excludes wells behind central receipt points)     206     223     192
Gathered volumes—TBtu/d     0.98     0.92     0.84
Incremental transportation volumes—TBtu/d(B)     0.46     0.39     0.39
   
 
 
  Total throughput volumes—TBtu/d     1.44     1.31     1.23
   
 
 
Natural gas processed—TBtu/d     0.54     0.52     0.50
Natural gas liquids sold (keep-whole)—million gallons     244     191     185
Natural gas liquids sold (purchased for resale)—million gallons     113     96     78
Natural gas liquids sold (percent-of-liquids)—million gallons     14     15     16
   
 
 
  Total natural gas liquids sold—million gallons     371     302     279
   
 
 
Average sales price per gallon   $ 0.901   $ 0.873   $ 0.720

(A)
Includes wells behind central receipt points (as reported to management by third parties). A central receipt point is a single receipt point into a gathering line where a producer aggregates the volumes from one or more wells and delivers them into the gathering system at a single meter site. This information is not available for years prior to 2006 as Enogex Predecessor's books and records were not maintained in a manner to provide this information for years prior to 2006.

(B)
Incremental transportation volumes (reported in trillion British thermal units per day) consist of natural gas moved only on the transportation pipeline.

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    Summary of Operating Results

        Enogex reported net income of approximately $62.8 million in the nine months ended September 30, 2007 as compared to approximately $90.4 million in the nine months ended September 30, 2006. This decrease was primarily due to a $36.0 million reduction in earnings associated with discontinued operations. In addition, higher gross margins in each of Enogex's segments were partially offset by higher operating expenses and higher depreciation expense.

        Enogex reported net income of approximately $113.5 million in 2006 as compared to approximately $94.5 million in 2005. This increase was primarily due to increased gross margin in each of its businesses largely as a result of higher commodity spreads and business growth in 2006 as compared to 2005. The increases in gross margin were partially offset by higher operation and maintenance expenses. Also contributing to the increase in net income were higher interest income and other income partially offset by lower net income from discontinued operations in 2006 as compared to 2005. Enogex reported net income of approximately $94.5 million in 2005 as compared to approximately $56.0 million in 2004. This increase was primarily due to higher net income from discontinued operations in 2005 as compared to 2004 and from an asset impairment charge recorded in 2004 with no similar item recorded in 2005. Enogex's consolidated gross margin for 2005 decreased approximately $4.3 million as compared to 2004 due to decreased gross margin in Enogex's marketing business and its transportation and storage business, which were only partially offset by increased gross margin in its gathering and processing business.

    Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

        Enogex's operating income increased approximately $21.5 million during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a higher gross margin in each of Enogex's segments, which was partially offset by higher operating expenses and higher depreciation expense.

        Gas imbalances affect Enogex's results of operations. Gas imbalances occur when the actual amounts of natural gas delivered from or received by Enogex's pipeline system differ from the amounts scheduled to be delivered or received. Imbalances due to shippers by Enogex are shown on Enogex's consolidated balance sheets as a liability and imbalances due to Enogex from shippers are shown as an asset on Enogex's consolidated balance sheets. Exclusive of changes in the price of natural gas, increases in the amount of imbalances shown as an asset, or decreases in the amount of imbalances shown as a liability, on Enogex's consolidated balance sheets increase Enogex's gross margin, while decreases in the amount of imbalances shown as an asset, or increases in the amount of imbalances shown as a liability, on Enogex's consolidated balance sheets decrease gross margin.

        Gross Margin

        Enogex's consolidated gross margin increased approximately $31.9 million during the nine months ended September 30, 2007 as compared to the same period in 2006. The increase resulted from a higher gross margin in the transportation and storage business ($15.0 million), the gathering and processing business ($4.8 million) and the marketing business ($12.1 million).

        The transportation and storage business contributed approximately $108.0 million of Enogex's consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $93.0 million during the same period in 2006, an increase of approximately $15.0 million, or 16.1%. The gross margin increased primarily due to:

    a change in Enogex's over-recovered position to an under-recovered position under its FERC-approved fuel tracker in the East Zone during the nine months ended September 30, 2007 as compared to the same period in 2006, which increased the gross margin by

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      approximately $8.5 million. Please see "Business—Our Business—Transportation and Storage—Regulation" for a discussion of the fuel tracker;

    the recognition of lower of cost or market adjustments related to natural gas inventories used to operate the pipeline in 2006, which reduced the 2006 gross margin by approximately $8.3 million for which there was no comparable item during the nine months ended September 30, 2007;

    increased demand fees due to entering into new contracts during the nine months ended September 30, 2007 with more favorable terms, which increased the gross margin by approximately $7.1 million; and

    the liability associated with a throughput contract which was transferred to the gathering and processing segment in the second quarter of 2007, which increased the gross margin by approximately $2.2 million.

        These increases in the transportation and storage gross margin were partially offset by:

    a reduction in fuel recoveries during the nine months ended September 30, 2007, which decreased the gross margin by approximately $5.3 million;

    a decrease in the net gas sales margin due to a decrease in natural gas prices during the nine months ended September 30, 2007, which decreased the gross margin by approximately $3.1 million; and

    decreased commodity, interruptible and low and high pressure revenues of approximately $2.5 million during the nine months ended September 30, 2007 due primarily to renegotiation of contracts to demand based contracts rather then commodity-based contracts in 2007 in addition to an interruptible storage contract that expired September 30, 2006.

        The gathering and processing business contributed approximately $126.8 million of Enogex's consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $122.0 million during the same period in 2006, an increase of approximately $4.8 million, or 3.9%. The gathering and processing gross margin increased primarily due to:

    reduced imbalance expense resulting from the recognition in the nine months ended September 30, 2006 of an approximately $3.2 million imbalance liability upon the transfer of imbalances previously recognized in the transportation and storage business coupled with an approximately $5.2 million net imbalance liability decrease in 2007 as compared to 2006, which increased the gross margin by approximately $8.4 million;

    renegotiated percent-of-liquids contracts entered into during 2007, which increased the gross margin by approximately $2.7 million;

    higher fees from low pressure contracts renegotiated with more favorable terms during the nine months ended September 30, 2007, which increased the gross margin by approximately $1.7 million;

    higher compression fees during the nine months ended September 30, 2007, which increased the gross margin by approximately $1.4 million;

    increased high pressure volumes due to new production in 2007, which increased the gross margin by approximately $1.3 million; and

    increased condensate margin due to higher index prices during the nine months ended September 30, 2007 as compared to the same period in 2006, which increased the gross margin by approximately $1.2 million.

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        These increases in the gathering and processing gross margin were partially offset by:

    a reduction in fuel recoveries during the nine months ended September 30, 2007, which decreased the gross margin by approximately $5.9 million;

    a reduction in Enogex's over recovered position of approximately $2.5 million during the nine months ended September 30, 2006 as compared to an increase of approximately $0.2 million during the nine months ended September 30, 2007, which decreased the gross margin during the nine months ended September 30, 2007 by approximately $2.7 million;

    a reduction in keep-whole activity during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to a decrease in the gas imbalance asset, which decreased the gross margin by approximately $2.2 million; and

    the settlement on a throughput contract during the nine months ended September 30, 2007, which decreased the gross margin by approximately $1.9 million.

        The marketing business contributed approximately $18.7 million of Enogex's consolidated gross margin during the nine months ended September 30, 2007 as compared to approximately $6.6 million during the same period in 2006, an increase of approximately $12.1 million. The gross margin increased primarily due to:

    realized gains from physical activity on a transportation contract, which increased the gross margin by approximately $23.9 million;

    a reduction in lower of cost or market adjustments related to natural gas held in storage during the nine months ended September 30, 2007 as compared to the same period in 2006, which increased the gross margin by approximately $6.6 million;

    gains on physical storage activity partially offset by higher fees, which increased the gross margin by approximately $3.4 million; and

    increased gains from other origination, optimization and trading activity, which increased the gross margin by approximately $2.6 million.

        These increases in the marketing gross margin were partially offset by:

    losses on economic hedges associated with various transportation contracts from recording these hedges at market value on September 30, 2007, which decreased the gross margin by approximately $12.6 million; and

    losses on economic hedges of natural gas storage inventory from recording these hedges at market value on September 30, 2007 as compared to September 30, 2006, which decreased the gross margin by approximately $11.8 million.

        Operating Income

        As shown above, Enogex's operating income is calculated by subtracting from the gross margin the following four items: (i) other operation and maintenance expenses, (ii) depreciation, (iii) impairment of assets and (iv) taxes other than income. Enogex's consolidated operating income for the nine months ended September 30, 2007 was approximately $118.7 million, a $21.5 million increase from its consolidated operating income for the nine months ended September 30, 2006. The increase was attributable primarily to the $31.9 million increase described above in consolidated gross margin, as the aggregate of other operation and maintenance expenses, depreciation expense, impairment of assets and taxes other than income was only approximately $10.4 million higher during the nine months ended September 30, 2007 as compared to the same period in 2006. The variances in depreciation expense and in taxes other than income on both a consolidated basis and by segment reflect differing levels of depreciable plant in service and a slight decrease in property taxes. The $8.1 million increase in other

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operation and maintenance expenses on a consolidated basis was primarily due to higher salaries, wages and other employee benefits due to higher incentive compensation and hiring additional employees and a sales and use tax refund received in the prior year.

        Specifically, by segment, other operation and maintenance expenses for the transportation and storage business were approximately $4.0 million, or 13.8%, higher during the nine months ended September 30, 2007 as compared to the same period in 2006 primarily due to higher salaries, wages and other employee benefits expense of approximately $3.7 million primarily due to higher incentive compensation and hiring additional employees to support business growth.

        Other operation and maintenance expenses for the gathering and processing business increased approximately $6.8 million, or 15.4%, during the nine months ended September 30, 2007 as compared to the same period in 2006. This increase was primarily due to higher allocations from Enogex of approximately $3.1 million primarily due to increased costs in 2007 and a sales and use tax refund of approximately $2.0 million received in May 2006 related to activity in prior years with no corresponding item in 2007.

        Other operation and maintenance expenses for the marketing business were approximately $2.7 million, or 37.5%, lower during the nine months ended September 30, 2007 as compared to the same period in 2006. The decrease was primarily due to a fee the marketing business began charging Enogex in 2007 related to hedging activities, lower salaries, wages and benefits due to a decrease in the number of marketing employees compared to 2006 partially offset by higher allocations from Enogex primarily due to increased costs in 2007.

        Consolidated Information

        Interest Income.    Enogex's consolidated interest income was approximately $7.0 million during the nine months ended September 30, 2007 as compared to approximately $8.7 million during the same period in 2006, a decrease of approximately $1.7 million, or 19.5%, primarily due to interest income earned on cash investments from the cash proceeds from the sale of certain gas gathering assets in the Kinta, Oklahoma area, referred to herein as the Kinta Assets, in May 2006. See "—Discontinued Operations."

        Other Income.    Enogex's consolidated other income was approximately $0.8 million during the nine months ended September 30, 2007 as compared to approximately $6.4 million during the same period in 2006, a decrease of approximately $5.6 million, or 87.5%, primarily due to a pre-tax litigation settlement of approximately $5.2 million in 2006 and a pre-tax gain of approximately $0.5 million in the first quarter of 2006 from the sale of small gathering sections of Enogex's pipeline.

        Income Tax Expense.    Enogex's consolidated income tax expense was approximately $39.3 million during the nine months ended September 30, 2007 as compared to approximately $33.9 million during the same period in 2006, an increase of approximately $5.4 million, or 15.9%, primarily due to higher pre-tax income.

        Non-Recurring and Timing Items.    For the nine months ended September 30, 2007, Enogex's consolidated net income of approximately $62.8 million included a loss of approximately $2.0 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2007. The offsetting gains from physical utilization of the transportation capacity are expected to be realized during the remainder of 2007. Also, for the nine months ended September 30, 2007, OERI recorded losses of approximately $2.2 million resulting from recording natural gas storage inventory at the lower of cost or market value. The offsetting gains from the sale of withdrawals from inventory are expected to be realized during the first quarter of 2008. As discussed above, in connection with the offering, Enogex distributed its shares of OERI to OGE Energy. During the nine months ended September 30, 2007, Enogex had no significant items that it does not consider to be reflective of its ongoing performance.

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        For the nine months ended September 30, 2006, Enogex's consolidated net income, including the discontinued operations discussed below under the caption "—Discontinued Operations," was approximately $90.4 million, which included a loss of less than approximately $0.1 million at OERI resulting from recording economic hedges associated with the Cheyenne Plains transportation contract at market value on September 30, 2006. The offsetting gains from physical utilization of the transportation capacity were realized during the remainder of 2006. Also, at September 30, 2006, OERI recorded a gain of approximately $6.2 million resulting from recording economic storage hedges at market value. The offsetting reductions in gains from the sale of withdrawals from inventory were realized during the remainder of 2006 and through the first quarter of 2007. Also, during the nine months ended September 30, 2006, Enogex had an increase in net income of approximately $40.6 million relating to various items that Enogex does not consider to be reflective of its ongoing performance. These increases in consolidated net income include:

    an after-tax gain on the sale of the Kinta Assets in the second quarter of 2006 of approximately $34.1 million;

    the approximately $3.2 million after-tax impact of a litigation settlement;

    income from discontinued operations of approximately $1.9 million;

    a sales and use tax refund related to activity in prior years of approximately $1.3 million after tax; and

    an after-tax gain of approximately $0.3 million from the sale of a small gathering section of Enogex's pipeline.

    2006 Compared to 2005

        Enogex's consolidated operating revenues and cost of goods sold decreased in 2006 approximately $2.0 billion, or 45.4%, and $2.0 billion, or 49.6%, respectively, as compared to 2005 primarily due to lower revenues and related costs in Enogex's marketing business, reflecting a reduction in trading activities due to a shift in strategy in Enogex's marketing business as Enogex continued to implement its refocused strategy that seeks to minimize the amount of capital employed and to complement better Enogex's businesses.

        Gross Margin

        Enogex's consolidated gross margin increased approximately $57.7 million in 2006 as compared to 2005 primarily due to increased gross margin in each of its businesses largely as a result of higher commodity spreads and business growth in 2006 as compared to 2005.

        The transportation and storage business contributed approximately $125.6 million of Enogex's consolidated gross margin in 2006 as compared to approximately $99.1 million in 2005, an increase of approximately $26.5 million, or 26.7%. The gross margin increased primarily due to:

    better management of gas pipeline imbalances as Enogex reduced its exposure to gas imbalances while taking advantage of favorable market price movement in 2006 and the transfer of certain imbalance liabilities previously carried by the transportation and storage business in 2005 to the gathering and processing business in 2006, which increased the gross margin by approximately $11.5 million in 2006;

    increased low and high pressure revenues primarily due to increased customer production and an increase in the allocated portion of bundled rates in 2006 resulting in increased rates of approximately $0.02 per MMBtu being recognized, which increased the gross margin by approximately $6.2 million;

    a change in Enogex's 2005 accounting estimate of the volume of natural gas in its natural gas storage inventory, which reduced the 2005 gross margin by approximately $5.7 million;

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    improved recovery of fuel as Enogex transitioned to zonal fuel rates in 2006, which increased the gross margin by approximately $4.7 million;

    storage hedging gains, which increased the gross margin by approximately $3.5 million; and

    increased gross margin recognized on natural gas sales of $0.628 per MMBtu as compared to 2005 due to favorable market conditions, which increased the gross margin by approximately $3.5 million.

        These increases in the transportation and storage gross margin were partially offset by a lower of cost or market adjustment related to natural gas inventory used to operate Enogex's pipelines during 2006, which reduced the 2006 gross margin by approximately $8.3 million as there was no comparable item during 2005.

        The gathering and processing business contributed approximately $167.6 million of Enogex's consolidated gross margin in 2006 as compared to approximately $140.2 million in 2005, an increase of approximately $27.4 million, or 19.5%. The gathering and processing gross margin increased primarily due to:

    increased net keep-whole margins primarily due to a $1.06 per MMBtu increase in natural gas prices coupled with an increase in NGL prices and increased volumes of 24.0 million gallons due to business growth, which increased the gross margin by approximately $33.5 million;

    increased contractual fuel gains primarily due to an increase of approximately $1.33 per MMBtu in recognized natural gas market prices in 2006 as compared to 2005, which increased the gross margin by approximately $4.9 million; and

    a reduction in Enogex's over-recovered fuel position as it transitioned to zonal fuel rates in 2006, which increased the gross margin by approximately $2.5 million.

        These increases in the gathering and processing gross margin were partially offset by the recognition of imbalance expense in 2006 (previously carried by the transportation and storage business in 2005), which reduced the gross margin by approximately $13.8 million in 2006.

        The marketing business contributed approximately $14.2 million of Enogex's consolidated gross margin in 2006 as compared to approximately $10.4 million in 2005, an increase of approximately $3.8 million, or 36.5%. The gross margin increased primarily due to:

    gains in storage activity due to timing, resulting from recording Enogex's storage hedges at market value at December 31, 2006 and an increase in storage capacity, which increased the gross margin by approximately $13.2 million; and

    an increase in the spread between natural gas prices at the receipt location of the Cheyenne Hub near the Colorado and Wyoming border and the natural gas prices at the delivery locations in south central Kansas, which increased the gross margin by approximately $7.6 million.

        These increases in the marketing gross margin were partially offset by:

    a lower of cost or market adjustment related to natural gas in storage during 2006, which reduced the 2006 gross margin by approximately $9.9 million; and

    lower gains in trading and park and loan transactions due to a lower level of activity in Enogex's marketing business and less favorable market conditions, which reduced the gross margin by approximately $6.0 million.

        Park and loan transactions are planned or managed gas imbalances related to the marketing of natural gas.

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        Operating Income

        Enogex's consolidated operating income increased $41.5 million in 2006 compared to 2005. This increase reflects the $57.7 million increase in gross margin on revenues discussed above, which was only partially offset by a $13.4 million increase (13.9%) in other operation and maintenance expenses, a $0.3 million impairment charge, and minor increases in depreciation of $1.9 million and taxes other than income of $0.6 million. The variances in depreciation and in taxes other than income on a consolidated basis and by business segment were attributable primarily to new assets placed into service and slightly higher property taxes. The increase in other operation and maintenance expenses on a consolidated basis was primarily due to:

    higher salaries, wages and other employee benefits of approximately $9.5 million primarily due to higher incentive compensation and hiring additional employees to support business growth; and

    higher materials and supplies costs of approximately $2.7 million primarily related to work performed to maintain the integrity and safety of Enogex's pipelines, higher cost of materials and increased material used at newly added facilities.

These same factors were the primary reasons for the increases in other operation and maintenance expenses by segment.

        For the transportation and storage business, other operation and maintenance expenses in 2006 increased $14.8 million due to higher salaries, wages and other employee benefits, $3.2 million due to decreased capitalized labor and $1.7 million due to higher materials and supplies costs. These increases were only partially offset by a change in 2006 in Enogex's internal methods for allocating other operation and maintenance expenses, which lowered the allocations by OGE Energy to the transportation and storage business by $10.3 million. Other operation and maintenance expenses increased $4.2 million in the gathering and processing business in 2006 due to a $9.6 million increase resulting from the change in such allocation method and $1.0 million from higher costs for materials and supplies. Offsetting these increases were lower salaries, wages and other employee benefits of $5.7 million and a sales and use tax refund of $2.0 million pertaining to activity in prior years. In the marketing business, other operation and maintenance expenses in 2006 increased $0.9 million, of which $0.7 million was attributable to the change in allocation methods and $0.4 million to higher wages, salaries and other employee benefits.

        Consolidated Information

        Interest Income.    Consolidated interest income was approximately $11.1 million in 2006 as compared to approximately $2.9 million in 2005, an increase of approximately $8.2 million primarily due to interest income earned on cash investments from the cash proceeds from the sale of Enogex Arkansas Pipeline Corporation, or EAPC, in October 2005 and the sale of the Kinta Assets in May 2006. See "—Discontinued Operations."

        Other Income.    Consolidated other income was approximately $7.7 million in 2006 as compared to approximately $0.8 million in 2005, an increase of approximately $6.9 million. The increase in other income was primarily due to:

    a pre-tax litigation settlement of approximately $5.2 million in 2006;

    a pre-tax gain of approximately $1.0 million in the fourth quarter of 2006 from the sale of certain west Texas pipeline assets; and

    a pre-tax gain of approximately $0.5 million in the first quarter of 2006 from the sale of small gathering sections of Enogex's pipeline.

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        Income Tax Expense.    Consolidated income tax expense was approximately $48.0 million in 2006 as compared to approximately $23.4 million in 2005, an increase of approximately $24.6 million primarily due to higher pre-tax income.

        Non-Recurring and Timing Items.    For 2006, Enogex's consolidated net income, including the discontinued operations discussed below under the caption "—Discontinued Operations," was approximately $113.5 million. During 2006, Enogex had an increase in net income of approximately $41.2 million relating to various items that it does not consider to be reflective of the ongoing profitability of its business. These increases in net income include:

    an after-tax gain on the sale of the Kinta Assets in the second quarter of 2006 of approximately $34.1 million;

    the approximately $3.2 million after-tax impact of a litigation settlement;

    income from discontinued operations of approximately $1.9 million;

    a sales and use tax refund related to activity in prior years of approximately $1.3 million after tax;

    an after-tax gain of approximately $0.6 million related to the sale of certain west Texas pipeline assets; and

    an after-tax gain of approximately $0.3 million from the sale of a small gathering section of Enogex's pipeline.

        These increases in net income were partially offset by a decrease in net income of approximately $0.2 million related to the impairment of certain long-lived assets.

        For 2005, Enogex's consolidated net income, including the discontinued operations discussed below under the caption "—Discontinued Operations," was approximately $94.5 million. During 2005, Enogex had an increase in net income of approximately $50.0 million relating to various items that it does not consider to be reflective of the ongoing profitability of its business. These increases in net income include:

    an after-tax gain on the sale of EAPC in October 2005 of approximately $36.7 million;

    income from discontinued operations of approximately $11.3 million;

    an after-tax gain on the sale of Enerven in August 2005 of approximately $1.8 million; and

    income from a sales tax refund related to activity in prior years of approximately $0.2 million.

    2005 Compared to 2004

        Enogex's consolidated operating revenues and cost of goods sold increased in 2005 approximately $967.9 million, or 28.7%, and $972.2 million, or 31.2%, respectively, as compared to 2004 primarily due to higher commodity prices and higher revenues and related costs in Enogex's marketing business in 2005 as compared to 2004.

        Gross Margin

        Enogex's consolidated gross margin decreased approximately $4.3 million in 2005 as compared to 2004 primarily due to lower gross margins in its marketing and transportation and storage businesses, which were partially offset by a higher gross margin in its gathering and processing business. Factors affecting gross margin by business segment are explained below.

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        The transportation and storage business contributed approximately $99.1 million of Enogex's consolidated gross margin in 2005 as compared to approximately $114.5 million in 2004, a decrease of approximately $15.4 million, or 13.4%. The gross margin decreased primarily due to:

    losses of gas in Enogex's storage fields, increased costs associated with natural gas purchases and sales, increased costs from electric compression, reduced fuel recoveries due to timing and system fuel volumes previously recorded in Enogex's transportation and storage business which are now being recorded in its gathering and processing business, which collectively reduced the gross margin by approximately $20.5 million; and

    reduced demand fees due to fewer overrun service charges with OG&E and the loss of firm contracts, which reduced the gross margin by approximately $2.1 million.

        These decreases in the transportation and storage gross margin were partially offset by:

    increased crosshaul rates of $0.139 per MMBtu and volumes of approximately 77,000 MMBtu in 2005 as compared to $0.115 per MMBtu and approximately 48,000 MMBtu in 2004 due to increased demand for crosshaul services as west to east basis spreads widened, which increased the gross margin by approximately $5.3 million; and

    increased commodity and interruptible revenues as a result of an increase in activity of approximately 22,000 MMBtu from several customers in 2005, which increased the gross margin by approximately $1.5 million.

        The gathering and processing business contributed approximately $140.2 million of Enogex's consolidated gross margin in 2005 as compared to approximately $123.4 million in 2004, an increase of approximately $16.8 million, or 13.6%. The gathering and processing gross margin increased primarily due to:

    contractual fuel gains primarily due to higher natural gas prices and renegotiated contracts, which increased the gross margin by approximately $7.2 million;

    increased fuel over recoveries due to higher natural gas prices, 2005 fuel reserve and system fuel volumes previously recorded in Enogex's transportation and storage business which is now being recorded in its gathering and processing business, which increased the gross margin by approximately $6.2 million;

    increased condensate liquid margins primarily due to higher condensate market prices of $0.434 per gallon in 2005 as compared to $0.249 per gallon in 2004, which increased the gross margin by approximately $3.0 million. Condensate is a by-product of gathering and is sold on the open market;

    an increase of approximately 28,000 MMBtu in compression and dehydration volumes in 2005 as compared to 2004 due to increased customer production activity, which increased the gross margin by approximately $2.5 million;

    higher volumes of approximately 283,000 MMBtu in 2005 as compared to 272,000 MMBtu in 2004 due to increased production activities of customers on the low pressure gathering systems, which increased the gross margin by approximately $2.2 million;

    increased percent-of-liquids margins primarily due to higher NGL prices of $0.817 per gallon in 2005 as compared to $0.677 per gallon in 2004 due to prevailing market conditions, which increased the gross margin by approximately $1.4 million; and

    higher margin on natural gas sales reflective of opportunities in the marketplace, which increased the gross margin by approximately $1.1 million.

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        These increases in the gathering and processing gross margin were partially offset by:

    decreased net keep-whole margins primarily due to a $1.22 per MMBtu increase in natural gas prices offset with an increase in activity of approximately 34.2 million gallons in 2005, which reduced the gross margin by approximately $3.2 million;

    an increase in utilization of electric compressors in 2005 due to higher natural gas prices, which reduced the gross margin by approximately $3.0 million; and

    a decrease in volumes of approximately 5.3 million MMBtu on the high pressure gathering systems due to production declines and wells moving to low pressure status, which reduced the gross margin by approximately $1.0 million.

        The marketing business contributed approximately $10.4 million of Enogex's consolidated gross margin in 2005 as compared to approximately $16.1 million in 2004, a decrease of approximately $5.7 million, or 35.4%. The gross margin decreased primarily due to:

    less favorable market conditions and trading activity, which reduced the gross margin by approximately $13.0 million; and

    losses incurred related to Enogex's position on the Cheyenne Plains' transportation agreement, which reduced the gross margin by approximately $3.6 million.

        These decreases in the marketing gross margin were partially offset by:

    park and loan transactions in 2004, which reduced the 2004 gross margin by approximately $7.7 million;

    lower demand fees paid for storage services due to establishing new rates for the new storage season, which began April 1, 2004 and increased the gross margin by approximately $2.5 million; and

    gains in storage activity, which increased the gross margin by approximately $0.7 million.

        Operating Income

        Enogex's consolidated operating income was $97.3 million in 2005 as compared to $95.6 million in 2004, an increase of $1.7 million despite the lower consolidated gross margin in 2005. The 2005 increase in operating income was primarily due to a net asset impairment charge of $7.8 million in 2004, with no similar item recorded in 2005. The impairment charge related to certain pipeline assets in the transportation and storage business that served a particular customer's electric generation facilities pursuant to a transportation agreement that was terminated by the customer effective December 31, 2004. Other factors affecting consolidated operating income were slight decreases in depreciation of $0.7 million and in taxes other than income of $0.6 million. The changes in these two items, both on a consolidated and business segment basis, were attributable to variances in plant in service and slightly lower property taxes. The other factor affecting Enogex's consolidated operating income was an increase of $3.1 million (3.3%) in other operation and maintenance expenses, which was primarily due to:

    higher outside service costs related to business development projects in 2005, system software implementation in 2005 and work performed to maintain the integrity and safety of Enogex's pipeline of approximately $4.4 million; and

    expenses related to a pipeline rupture in the second quarter of 2005 of approximately $0.5 million.

        These increases in other operation and maintenance expenses were partially offset by an uncollectible debt reserve of approximately $1.1 million recorded in 2004 with no similar reserve

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recorded in 2005 due to increased efforts to collect on customer receivables. Each of the foregoing items pertained almost entirely to the transportation and storage business.

        Other factors affecting other operation and maintenance expenses in the transportation and storage business were higher allocations from OGE Energy of approximately $2.7 million. These increases in other operation and maintenance expenses for the transportation and storage business were offset in part by increased capitalized labor of approximately $3.2 million, lower salaries, wages and other employee benefits of approximately $0.8 million primarily due to more employee costs being capitalized in 2005 and an uncollectible debt reserve of approximately $0.8 million recorded in 2004 with no similar reserve recorded in 2005.

        For the gathering and processing business, other operation and maintenance expenses were approximately $55.3 million in 2005 as compared to approximately $51.3 million in 2004, an increase of approximately $4.0 million, or 7.8%. The increase was due to higher salaries, wages and other employee benefits of approximately $3.7 million primarily due to a change in allocation methods. In the marketing business, other operation and maintenance expenses decreased primarily due to lower allocations from OGE Energy of approximately $3.4 million due to a change in allocation rates, lower salaries, wages and other employee benefits of approximately $0.8 million primarily due to a reduction in incentive compensation in 2004 and an uncollectible debt reserve of approximately $0.3 million recorded in 2004 with no similar reserve recorded in 2005. These decreases in other operation and maintenance expenses were partially offset by higher outside service costs related to a capital allocation study and system software implementation in 2005 of approximately $0.3 million.

        Consolidated Information

        Interest Income.    Consolidated interest income was approximately $2.9 million in 2005 as compared to approximately $3.2 million in 2004, a decrease of approximately $0.3 million, or 9.4%, primarily due to a decrease in interest income of approximately $1.9 million due to the interest portion of an income tax refund related to prior periods which was received in 2004 with no similar activity recorded in 2005 partially offset by an increase in interest income of approximately $1.1 million from parent due to funds received from the sale of EAPC in October 2005.

        Other Income.    Consolidated other income was approximately $0.8 million in 2005 as compared to approximately $4.5 million in 2004, a decrease of approximately $3.7 million, or 82.2%. The decrease in other income was primarily due to a gain in 2004 of approximately $3.0 million from the sale of certain of Enogex's compression and processing assets in 2004 in addition to approximately $0.8 million received related to a bankruptcy settlement from one of Enogex's customers during the third quarter of 2004.

        Income Tax Expense.    Consolidated income tax expense was approximately $23.4 million in 2005 as compared to approximately $26.4 million in 2004, a decrease of approximately $3.0 million, or 11.4%. The decrease in income tax expense was primarily due to:

    lower pre-tax income; and

    a reduction in excess deferred taxes of approximately $3.2 million in 2005.

        These decreases in income tax expense were partially offset by a decrease in Oklahoma state income tax credits of approximately $1.6 million in 2005 as compared to 2004.

        Non-Recurring and Timing Items.    For 2005, Enogex's consolidated net income, including the discontinued operations, discussed below under the caption "—Discontinued Operations," was approximately $94.5 million. During 2005, Enogex had an increase in net income of approximately $50.0 million relating to various items that Enogex does not consider to be reflective of the ongoing profitability of its business. These increases in net income include:

    a gain on the sale of EAPC in October 2005 of approximately $36.7 million;

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    income from discontinued operations of approximately $11.3 million;

    a gain on the sale of Enerven in August 2005 of approximately $1.8 million; and

    income from a sales tax refund related to activity in prior years of approximately $0.2 million.

        For 2004, Enogex's consolidated net income, including the discontinued operations, discussed below under the caption "—Discontinued Operations," was approximately $56.0 million. During 2004, Enogex had an increase in net income of approximately $15.6 million relating to various items that Enogex does not consider to be reflective of the ongoing profitability of its business. These increases in net income include:

    income from discontinued operations of approximately $11.7 million;

    authorized recovery of previously under-recovered fuel of approximately $3.8 million;

    a gain on the sale of Enogex's compression and processing assets of approximately $1.8 million;

    an imbalance settlement with a customer of approximately $1.6 million;

    a net Oklahoma investment tax credit of approximately $1.0 million; and

    a settlement related to a customer bankruptcy of approximately $0.5 million.

        These increases to net income were partially offset by a net impairment charge of approximately $4.8 million.

    Discontinued Operations

        In March 2006, Enogex announced that its wholly owned subsidiary, Enogex Gas Gathering, L.L.C., had entered into an agreement to sell the Kinta Assets, which included approximately 568 miles of gathering pipeline and 22 compressor units with current volumes of approximately 145 MMcf/d, all in eastern Oklahoma. The sale price was approximately $93 million. This transaction closed on May 1, 2006 and Enogex recorded an after tax gain of approximately $34.1 million during the second quarter of 2006. The proceeds from the sale were used, among other things, to reduce short-term debt levels and fund capital expenditures.

        In September 2005, Enogex announced that it had entered into an agreement to sell its interest in EAPC, which held a 75% interest in the NOARK Pipeline System Limited Partnership. This sale was completed on October 31, 2005. Enogex received approximately $177.4 million in cash proceeds and recognized an after tax gain of approximately $36.7 million from the sale of this business in the fourth quarter of 2005. Enogex used approximately $31.9 million of the proceeds to repay principal and accrued interest on long-term debt and approximately $46.7 million to pay taxes associated with EAPC. The balance of the proceeds of approximately $98.8 million was used, among other things, to reduce short-term debt levels and fund capital expenditures.

        In April 2005, Enogex Compression Company, LLC, or Enogex Compression, received an unsolicited offer to buy its interest in Enerven, a joint venture focused on the rental of natural gas compression assets. After evaluating this offer, Enogex Compression sold its interest in Enerven for approximately $7.3 million in August 2005. Enogex Compression recognized an after tax gain of approximately $1.8 million related to the sale of this business.

        As a result of these sale transactions, the Kinta Assets, which were part of the transportation and storage and gathering and processing segments, have been reported as discontinued operations for the nine months ended September 30, 2006 and Enogex Compression's interest in Enerven, Enogex's interest in EAPC and the Kinta Assets have been reported as discontinued operations for the years ended December 31, 2006, 2005 and 2004 in the consolidated financial statements. Enogex Compression's sale of its Enerven interest and Enogex's sale of its EAPC interest were completed

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during 2005 and, therefore, there are no results of operations for these transactions during 2006. Results for these discontinued operations are summarized and discussed below.

 
  Nine Months Ended
September 30,

  Year Ended December 31,
 
  2007
  2006
  2006
  2005
  2004
 
  (in millions)

Operating revenues   $   $ 9.4   $ 9.4   $ 106.0   $ 120.1
Cost of goods sold         4.9     4.9     69.5     80.0
   
 
 
 
 
Gross margin on revenues         4.5     4.5     36.5     40.1
Other operation and maintenance         1.0     1.0     7.5     7.9
Depreciation         0.3     0.3     5.8     6.5
Taxes other than income         0.1     0.1     1.3     1.5
   
 
 
 
 
Operating income         3.1     3.1     21.9     24.2
   
 
 
 
 
Interest income                 0.2     0.3
Other income         56.0     56.0     66.2    
Other expense                 0.1     0.6
Interest expense                 4.0     5.3
Income tax expense         23.1     23.1     34.4     7.0
   
 
 
 
 
Net income   $   $ 36.0   $ 36.0   $ 49.8   $ 11.6
   
 
 
 
 

        Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

        Following the sale of the Kinta Assets in May 2006, no operations of the Kinta Assets are reflected in the consolidated financial statements.

        2006 Compared to 2005

        Gross margin decreased approximately $32.0 million, or 87.7%, in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005, the sale of the Kinta Assets in May 2006 and a decrease in natural gas purchases and sales due to a decrease in natural gas transported prior to these assets being sold.

        Operation and maintenance expenses decreased approximately $6.5 million, or 86.7%, in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005 and the sale of the Kinta Assets in May 2006.

        Depreciation decreased approximately $5.5 million, or 94.8%, in 2006 as compared to 2005 primarily due to the sale of EAPC in October 2005 and ceasing depreciation in January 2006 when the Kinta Assets were reported as a discontinued operation.

        Taxes other than income decreased approximately $1.2 million, or 92.3%, in 2006 as compared to 2005 for ad valorem taxes primarily due to the sale of EAPC in October 2005.

        Other income decreased approximately $10.2 million, or 15.4%, in 2006 as compared to 2005 due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

        Interest expense decreased approximately $4.0 million, or 100.0%, in 2006 as compared to 2005 due to the sale of EAPC in October 2005 and the use of a portion of the sale proceeds to repay EAPC long-term debt.

        Income tax expense increased approximately $11.3 million, or 32.8%, in 2006 as compared to 2005 primarily due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

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        2005 Compared to 2004

        Gross margin decreased approximately $3.6 million, or 9.0%, in 2005 as compared to 2004 primarily due to the sale of EAPC in October 2005 and a decrease in natural gas purchases and sales due to a decrease in natural gas transported prior to these assets being sold.

        Other income increased approximately $66.2 million in 2005 as compared to 2004 due to a pre-tax gain of approximately $63.3 million recognized in the fourth quarter of 2005 related to the sale of EAPC and a pre-tax gain of approximately $2.9 million recognized in the third quarter of 2005 related to the sale of Enerven.

        Interest expense decreased approximately $1.3 million, or 24.5%, in 2005 as compared to 2004 due to the sale of EAPC in October 2005 and the use of a portion of the sale proceeds to repay EAPC long-term debt.

        Income tax expense increased approximately $27.4 million in 2005 as compared to 2004 primarily due to the sale of the Kinta Assets in May 2006 partially offset by the sale of EAPC in October 2005 and the sale of Enerven in August 2005.

Financial Condition

    September 30, 2007 Compared to December 31, 2006

        The balance of Accounts Receivable, Net was approximately $128.4 million and $205.6 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $77.2 million, or 37.5%, primarily due to lower natural gas sales prices of $5.16 per MMBtu at September 30, 2007 compared to $7.28 per MMBtu at December 31, 2006 for OERI.

        The balance of Advances to Parent was approximately $85.7 million and $144.4 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $58.8 million, or 40.7%, primarily due to repurchases of Enogex's common stock in 2007 partially offset by a decrease in intercompany income taxes payable in 2007.

        The balance of current Price Risk Management assets was approximately $9.2 million and $37.4 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $28.2 million, or 75.4%. The decrease was primarily due to OERI's physical purchases and sales activity recorded at December 31, 2006 being realized during the first nine months of 2007 partially offset by new physical activity and an increase in the value of existing activity. The decrease was also related to transportation hedges recorded at December 31, 2006 being realized during the first nine months of 2007 partially offset by new Cheyenne Plains and other transportation hedges.

        The balance of Construction Work in Progress was approximately $31.7 million and $11.1 million at September 30, 2007 and December 31, 2006, respectively, an increase of approximately $20.6 million primarily due to the construction of a processing plant and gathering system expansion projects.

        The balance of Accounts Payable was approximately $130.5 million and $195.0 million at September 30, 2007 and December 31, 2006, respectively, a decrease of approximately $64.5 million, or 33.1%, primarily due to a decrease in average natural gas prices of $5.31 per MMBtu at September 30, 2007 compared to $6.89 per MMBtu at December 31, 2006.

    December 31, 2006 Compared to December 31, 2005

        The balance of Accounts Receivable, Net was approximately $205.6 million and $437.0 million at December 31, 2006 and 2005, respectively, a decrease of approximately $231.4 million, or 53.0%, primarily due to lower average natural gas sales prices for OERI of $7.28 per MMBtu at December 31, 2006 compared to $10.43 per MMBtu at December 31, 2005.

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        The balance of Advances to Parent was approximately $144.4 million and $125.5 million at December 31, 2006 and 2005, respectively, an increase of approximately $18.9 million, or 15.1%, primarily due to a reduction in income taxes payable to OGE Energy in 2006 due to the disposal of a discontinued asset tax liability and related gains in 2005.

        The balance of current Price Risk Management assets was approximately $37.4 million and $89.0 million at December 31, 2006 and 2005, respectively, a decrease of approximately $51.6 million, or 58.0%. The decrease was primarily due to lower natural gas prices associated with OERI short-term physical natural gas purchase transactions and associated financial contracts. The inside FERC Panhandle Eastern Pipeline Company first of the month index for the month of December 2006 was $5.52 per MMBtu down from $8.76 per MMBtu for the month of December 2005. The volume of OERI's physical purchase and sales recorded at December 31, 2006 was 73 million MMBtu, down from 124.8 million MMBtu at December 31, 2005. OERI's short-term physical natural gas activity and associated financial contracts outstanding at December 31, 2006 from December 31, 2005 also contributed to the decrease.

        The balance of Gas Imbalance asset was approximately $2.8 million and $32.0 million at December 31, 2006 and 2005, respectively, a decrease of approximately $29.2 million, or 91.3%. The Gas Imbalance asset is comprised of planned or managed imbalances related to OERI's business, referred to herein as park and loan transactions, and pipeline and NGL imbalances, which are operational imbalances. Park and loan transactions were approximately $15.7 million at December 31, 2005 with no comparable balance at December 31, 2006. The decrease in park and loan transactions was due to the expiration of 2005 park and loan transactions in OERI's business activities. Operational imbalances were approximately $2.8 million and $16.3 million at December 31, 2006 and 2005, respectively, a decrease of approximately $13.5 million, or 82.8%. The decrease in operational imbalances was primarily due to Enogex beginning to manage imbalances related to its storage operations on a combined basis in 2006 for its two storage facilities, which resulted in a decrease in net imbalance volumes.

        The balance of Accounts Payable was approximately $195.0 million and $391.3 million at December 31, 2006 and 2005, respectively, a decrease of approximately $196.3 million, or 50.2%, primarily due to lower average natural gas prices for OERI of $6.89 per MMBtu at December 31, 2006 compared to $10.20 per MMBtu at December 31, 2005.

        The balance of current Price Risk Management liabilities was approximately $5.6 million and $81.9 million at December 31, 2006 and 2005, respectively, a decrease of approximately $76.3 million, or 93.2%. The decrease was primarily due to lower natural gas prices associated with OERI's short-term physical natural gas purchase transactions and associated financial contracts. The inside FERC Panhandle Eastern Pipeline Company first of the month index for the month of December 2006 was $5.52 per MMBtu down from $8.76 per MMBtu for the month of December 2005. The volume of OERI's physical purchase and sales recorded at December 31, 2006 was 73 million MMBtu, down from 124.8 million MMBtu at December 31, 2005. OERI's short-term physical natural gas activity and associated financial contracts outstanding at December 31, 2006 from December 31, 2005 also contributed to the decrease.

        The balance of Gas Imbalance liability was approximately $11.1 million and $35.8 million at December 31, 2006 and 2005, respectively, a decrease of approximately $24.7 million, or 69.0%. The Gas Imbalance liability is comprised of park and loan transactions, and pipeline and NGLs imbalances, which are operational imbalances. Park and loan transactions were approximately $10.2 million at December 31, 2005 with no comparable balance at December 31, 2006. The decrease in park and loan transactions was due to the expiration of 2005 park and loan transactions in OERI's business activities. Operational imbalances were approximately $11.1 million and $25.6 million at December 31, 2006 and 2005, respectively, a decrease of approximately $14.5 million, or 56.6%. The decrease in operational imbalances was primarily due to Enogex beginning to manage imbalances related to its storage

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operations on a combined basis in 2006 for its two storage facilities, which resulted in a decrease in net imbalance volumes.

Off-Balance Sheet Arrangements

        Off-balance sheet arrangements include any transactions, agreements or other contractual arrangements to which an unconsolidated entity is a party and under which we or Enogex have: (1) any obligation under a guarantee contract having specific characteristics as defined in FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others"; (2) a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to such entity for such assets; (3) any obligation, including a contingent obligation, under a contract that would be accounted for as a derivative instrument but is indexed to our own units and is classified in equity in our consolidated balance sheets; or (4) any obligation, including a contingent obligation, arising out of a variable interest as defined in FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51," in an unconsolidated entity that is held by, and material to, us or Enogex, where such entity provides financing, liquidity, market risk or credit risk support to, or engages in leasing, hedging or research and development services with, us or Enogex. Neither we nor Enogex currently have any off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our or Enogex's financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Liquidity and Capital Resources

        Historically, Enogex's sources of liquidity have included cash generated from operations, proceeds from the sale of assets and proceeds from the issuance of long-term debt. Enogex has also utilized short-term borrowings from OGE Energy to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged. All cash flow in excess of operating expenses and capital expenditures was transferred to OGE Energy under an intercompany borrowing agreement and appears in the consolidated financial statements as "Advances to Parent." Enogex was paid market rates on its cash balances. There have been no borrowings by Enogex under this intercompany arrangement since October 2005. In connection with this offering, OGE Energy and Enogex expect to amend the intercompany borrowing agreement to increase the maximum amount permitted to be borrowed by Enogex to $500 million. The maximum permitted borrowing limit will be reduced to $400 million on the six-month anniversary of the date of the amendment.

        Changes in working capital reflect the seasonal nature of Enogex's business and the revenue lag between billing and collection from customers.

        Also contributing to Enogex's liquidity has been the disposition of certain assets classified as discontinued operations in 2005 and 2006. During 2005 and 2006, these dispositions have generated net sales proceeds of approximately $277.7 million. Sales proceeds generated to date have been used to fund capital expenditures and as advances to OGE Energy.

        Additional asset sales could further contribute to Enogex's liquidity.

        In addition to the receipt of a contribution from us of a portion of the proceeds from this offering for working capital and other needs, Enogex expects its ongoing sources of liquidity to include cash generated from operations, Enogex's anticipated $250 million credit facility, long-term debt offerings, including Enogex's anticipated issuance of $300 million of new long-term debt, short-term borrowings from OGE Energy and cash infusions from us out of proceeds from the issuance of additional limited partner units. We believe that cash generated from these sources will be sufficient to meet Enogex's short-term working capital requirements, long-term capital expenditures program and monthly cash distributions to its members, including us.

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        Although the terms of the new $250 million credit facility have not been finalized, Enogex's new credit facility is expected to contain covenants and provisions that affect us, Enogex and its restricted subsidiaries, including, without limitation customary covenants and provisions:

    prohibiting Enogex from creating or incurring indebtedness if such incurrence would cause a breach of the consolidated leverage ratio described below and prohibiting Enogex's restricted subsidiaries from creating or incurring indebtedness (except for certain specified permitted indebtedness) in excess of the greater of (1) $200,000,000 and (2) 15% of the consolidated tangible net assets of Enogex and its restricted subsidiaries;

    prohibiting Enogex and its restricted subsidiaries from creating or incurring certain liens on their respective properties (subject to enumerated exceptions) securing indebtedness in excess of the greater of (1) $200,000,000 and (2) 15% of the consolidated tangible net assets of Enogex and its restricted subsidiaries;

    prohibiting Enogex from making distributions in certain circumstances, such as if any default or event of default occurs; provided that, among other things, so long as no matured event of default exists or would result therefrom, Enogex will be permitted to make distributions to fund distributions in amounts not to exceed the greater of (1) the amount by which Enogex's cash on hand exceeds its current and anticipated needs and (2) the aggregate amount necessary to provide us with any shortfall in available cash to fund the minimum quarterly distributions to unitholders;

    prohibiting consolidations, mergers and asset transfers by Enogex and its restricted subsidiaries (subject to enumerated exceptions);

    prohibiting Enogex and its restricted subsidiaries from entering into transactions with affiliates (other than Enogex or any of its subsidiaries) other than on terms no less favorable to Enogex or any such subsidiary than those which would be obtainable in a transaction with an unrelated third party (subject to enumerated exceptions, including the making of distributions to us as described above); and

    prohibiting Enogex and its restricted subsidiaries from entering lines of business that are not substantially the same as those being currently conducted and other business reasonably related to those businesses.

        We also expect that the credit facility will require Enogex to maintain, as of the end of each fiscal quarter, a consolidated leverage ratio (consolidated funded indebtedness to consolidated EBITDA (in each case, as defined in the credit facility)) of no greater than 5.00-to-1.00 for any four consecutive quarters, and no greater than 5.50-to-1.00 for any three consecutive quarters subsequent to the consummation of one or more specified permitted acquisitions having an aggregate value greater than $25 million during the prior twelve-month period. In case of a capital construction or expansion project in excess of $20 million, pro forma adjustments to consolidated EBITDA, approved by the lenders, may be made based on the percentage of capital costs expended and projected cash flows for the project. Such adjustments will be limited to 20% of actual EBITDA.

    Cash Flows

 
  Nine Months Ended
September 30,

   
   
   
 
 
  Year Ended December 31,
 
Enogex Predecessor

 
  2007
  2006
  2006
  2005
  2004
 
 
  (in millions)

 
Net cash provided from operating activities   $ 69.0   $ 73.8   $ 131.6   $ 235.2   $ 118.2  
Net cash used in investing activities   $ (96.3 ) $ (49.1 ) $ (65.1 ) $ (34.5 ) $ (22.5 )
Net cash provided from (used in) financing activities   $ 29.2   $ (20.9 ) $ (139.4 ) $ (304.0 ) $ (118.6 )

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        The reduction of approximately $4.8 million in net cash provided from operating activities during the nine months ended September 30, 2007 as compared to the same period in 2006 was primarily related to changes to working capital and other liabilities partially offset by changes to price risk management assets and liabilities. The reduction of approximately $103.6 million in net cash provided from operating activities in 2006 as compared to 2005 was primarily related to the $81.3 million decrease in changes to working capital and changes to price risk management assets and liabilities partially offset by higher levels of net income and deferred taxes. The increase of approximately $117.0 million in net cash provided from operating activities in 2005 as compared to 2004 was primarily related to the $113.7 million increase in changes to working capital.

        The increase in net cash used in investing activities of approximately $47.2 million during the nine months ended September 30, 2007 as compared to the same period in 2006 related to higher levels of capital expenditures. The increase in net cash used in investing activities of approximately $30.6 million in 2006 as compared to 2005 related to higher levels of capital expenditures primarily due to expansion in the Texas Panhandle. The increase in net cash used in investing activities of approximately $12.0 million in 2005 as compared to 2004 related to higher levels of capital expenditures primarily due to expansion in the Texas Panhandle and lower proceeds from asset sales.

        The increase in net cash provided from financing activities of approximately $50.1 million during the nine months ended September 30, 2007 as compared to the same period in 2006 related primarily to lower levels of repurchases of Enogex's common stock and lower levels of dividends paid to OGE Energy on Enogex's common stock, partially offset by a decrease in short-term debt proceeds. The decrease in net cash used in financing activities of approximately $164.6 million in 2006 as compared to 2005 related primarily to lower levels of advances to parent and maturities of long-term debt. The increase in net cash used in financing activities of approximately $185.4 million in 2005 as compared to 2004 relates primarily to higher levels of dividends paid to OGE Energy on Enogex's common stock owned by OGE Energy and higher levels of advances to parent from the proceeds received from the sale of assets classified as discontinued operations partially offset by lower maturities of long-term debt.

    Capital Expenditures

        Our businesses are capital-intensive and require investment to upgrade or enhance existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. The capital investment for these businesses consists primarily of:

    maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of Enogex's assets and extend their useful lives, connect new wells to Enogex's system or comply with environmental or safety regulations; and

    expansion capital expenditures such as those to expand and upgrade plant or pipeline capacity and to construct new plants or pipelines.

        We estimate that maintenance capital expenditures for Enogex's assets will be approximately $32.2 million for 2007, of which approximately $26.5 million was reflected as of September 30, 2007.

        We estimate that expansion capital expenditures for Enogex's assets will be approximately $126.2 million for 2007, of which approximately $70.1 million was reflected as of September 30, 2007.

        Below is a table showing expansion and maintenance capital expenditures for 2005 and 2006 and forecasted expansion and maintenance capital expenditures for 2007 and 2008. Please see "Cash

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Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Capital Expenditures."

 
  Actual
  Forecasted
 
  2005
  2006
  2007
  2008
Maintenance capital expenditures(1)   $ 32.0   $ 26.0   $ 32.2   $ 23.0
Expansion capital expenditures     2.8     41.1     126.2     168.1
   
 
 
 
  Total   $ 34.8   $ 67.1   $ 158.4   $ 191.1
   
 
 
 

(1)
Of the total historical and forecasted maintenance capital expenditures, approximately $2.5 million for 2005, $0.8 million for 2006, $2.0 million for 2007 and $0.9 million for 2008 are attributable to compliance with environmental regulations.

        During 2005 and 2006, approximately $2.7 million and $40.5 million, respectively, of Enogex's capital expenditures related to expansion into the Texas Panhandle. During 2007, approximately $43.4 million of Enogex's capital expenditures related to expansions in the Woodford Shale play, approximately $22.9 million related to expansions in the Texas Panhandle, approximately $20.3 million related to the Midcontinent Express and Boardwalk's Gulf Crossing pipeline projects, approximately $15.3 million related to processing upgrades and approximately $10.7 million related to expansion in Western Oklahoma. During 2008, approximately $43.1 million of Enogex's forecasted capital expenditures relate to the Midcontinent Express and Boardwalk's Gulf Crossing pipeline projects, approximately $40.4 million relate to expansions in Western Oklahoma, approximately $38.4 million relate to expansions in the Woodford Shale play, approximately $20.0 million relate to processing upgrades and approximately $2.3 million relate to expansions in the Texas Panhandle. For a further discussion of Enogex's expansion activities, please see "Business—Recent System Expansions."

    Contractual Obligations

        Enogex's contractual obligations estimated for the five-year period from January 1, 2007 through December 31, 2011 and beyond were as follows:

 
  Total
  Less than
1 year
(2007)

  1-3 years
(2008-2009)

  3-5 years
(2010-2011)

  More than
5 years

 
  (in millions)

Maturities of long-term debt   $ 401.0   $   $ 1.0   $ 400.0    
Interest payments on long-term debt     96.3     31.8     63.2     1.3    
Pension funding obligations     14.2     4.4     5.2     4.6     N/A
   
 
 
 
 
  Total debt and pension obligations     511.5     36.2     69.4     405.9    
Noncancellable operating lease obligations     8.6     2.2     3.1     2.9   $ 0.4
Other purchase obligations and commitments     53.4     6.9     12.4     13.0     21.1
   
 
 
 
 
  Total debt, pension and operating lease obligations and other purchase obligations and commitments   $ 573.5   $ 45.3   $ 84.9   $ 421.8   $ 21.5
   
 
 
 
 


N/A—Not
available

        In 2006, Enogex's contractual obligations were approximately $49.6 million, of which approximately $38.9 million related to long-term debt and pension obligations. This compares to contractual obligations in 2005 of approximately $77.6 million, of which approximately $73.3 million related to long-term debt and pension obligations.

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        Maturities of Enogex's long-term debt during the next five years consist of $1.0 million in 2008 and $400.0 million in 2010. There are no remaining maturities of Enogex's long-term debt in years 2007, 2009 or 2011. The partnership does not have any long-term debt outstanding. In connection with this offering, Enogex currently expects to redeem the $400 million of long-term debt due in 2010 with a combination of approximately $300 million of short-term borrowings from OGE Energy, borrowings under its new credit facility and proceeds of this offering that are expected to be contributed to Enogex. Proceeds from an issuance of $300 million of new long-term debt, with maturities ranging from two to 30 years, are expected to be utilized to repay amounts borrowed from OGE Energy in connection with the redemption.

    Pension and Postretirement Benefit Plans

        All of Enogex's eligible employees are covered by a non-contributory defined benefit pension plan sponsored by OGE Energy. During 2006, actual asset returns for this defined benefit pension plan were positively affected by growth in the equity markets. At December 31, 2006, approximately 64% of the pension plan assets were invested in listed common stocks with the balance invested in corporate debt and U.S. Government securities. In 2006, asset returns on the pension plan were approximately 14.5% as compared to approximately 6.2% in 2005. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.

        OGE Energy's contributions to the pension plan increased from approximately $32.0 million in 2005, of which approximately $2.3 million was allocated to Enogex, to approximately $90.0 million in 2006, of which approximately $7.0 million was allocated to Enogex. This increase in pension plan contributions in 2006 was to maintain an adequate funded status. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2007, OGE Energy contributed approximately $50.0 million to its pension plan, of which approximately $4.4 million was allocated to Enogex.

        In accordance with SFAS No. 88, "Employer's Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During 2006, Enogex experienced an increase in both the number of employees electing to retire and the amount of lump-sum payments to be paid to such employees upon retirement in 2006. As a result, Enogex recorded a pension settlement charge for 2006 of approximately $0.8 million in the fourth quarter of 2006. The pension settlement charge did not require a cash outlay and did not increase Enogex's total pension expense over time, as the charge was an acceleration of costs that otherwise would have been recognized as pension expense in future periods.

        As discussed in Note 11 of Notes to Consolidated Financial Statements, in 2000, OGE Energy made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired after January 31, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, Enogex's cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, Enogex's cash requirements should decrease and will be much less sensitive to changes in discount rates.

        At December 31, 2006, the projected benefit obligation and fair value of assets of Enogex's portion of OGE Energy's pension plan and restoration of retirement income plan was approximately

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$41.7 million and $42.7 million, respectively, for an overfunded status of approximately $1.0 million. The above amounts have been recorded in Prepaid Pension and Benefit Obligations with the offset in Accumulated Other Comprehensive Income in the consolidated balance sheets. The entry did not impact the results of operations in 2006 and did not require a usage of cash and is therefore excluded from the consolidated statements of cash flows. The amounts in Accumulated Other Comprehensive Income represent a net periodic pension cost to be recognized in the consolidated statements of income in future periods.

        During 2005, OGE Energy made contributions to the pension plan that exceeded amounts previously recognized as net periodic pension expense and recorded a net prepaid benefit obligation at December 31, 2005 of approximately $88.9 million, of which approximately $7.7 million was allocated to Enogex. At December 31, 2005, Enogex's portion of the projected pension benefit obligation exceeded the fair value of the pension plan assets by approximately $4.1 million. As a result of recording a prepaid benefit obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan assets, provisions of SFAS No. 87 required the recognition of an additional minimum liability in the amount of approximately $181.4 million for OGE Energy, of which approximately $0.1 million was allocated to Enogex at December 31, 2005. The offset of this entry was an intangible asset and Accumulated Other Comprehensive Income, net of a deferred tax asset; therefore, this adjustment did not impact the results of operations in 2005 and did not require a usage of cash and is therefore excluded from the consolidated statements of cash flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the remainder recorded in Accumulated Other Comprehensive Income. The amount in Accumulated Other Comprehensive Income represents a net periodic pension cost to be recognized in the consolidated statements of income in future periods.

        On August 17, 2006, President Bush signed The Pension Protection Act of 2006, or the Pension Protection Act, into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants. Management is currently analyzing the impact of the Pension Protection Act on Enogex's pension plans.

Security Ratings

 
  Moody's
  Standard & Poor's
  Fitch's
Enogex Notes(1)   Baa3   BBB   BBB

(1)
Enogex currently expects to redeem its $400 million 8.125% senior notes due 2010, and pay approximately $2.5 million of interest that will be accrued and unpaid through the redemption date and a make-whole premium of approximately $39.0 million, with a combination of approximately $300 million of short-term borrowings from OGE Energy, approximately $11.3 million of the $13.9 million of initial borrowings under its new credit facility and the approximately $130.2 million of net proceeds of this offering that we expect to contribute to Enogex for the anticipated repayment of that debt. Enogex expects to repay the amounts borrowed from OGE Energy for the redemption of its $400 million 8.125% senior notes due 2010 with the proceeds of an issuance of up to $300 million of new long-term debt.

        A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

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        Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, commodity prices, levels of drilling activity, acquisitions of other businesses or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations and new legislation.

Critical Accounting Policies and Estimates

        The consolidated financial statements and notes contain information that is pertinent to Management's Discussion and Analysis of Financial Condition and Results of Operations. In preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material affect on the consolidated financial statements. However, management believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact on us or Enogex that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas in which it exercises the most significant judgment are in the valuation of pension plan assumptions, impairment estimates, contingency reserves, fair value and cash flow hedges, operating revenues, natural gas purchases, the allowance for uncollectible accounts receivable and the valuation of energy purchase and sale contracts. The selection, application and disclosure of the following critical accounting estimates have been discussed with the audit committee of OGE Energy.

    Pension and Postretirement Benefit Plans

        OGE Energy has defined benefit retirement and postretirement plans that cover substantially all of Enogex's employees. Enogex expects to continue to participate in these plans following completion of this offering. Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and the level of funding. These expectations and assumptions are made by management of OGE Energy. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. The pension plan rate assumptions are shown in Note 11 of Notes to Consolidated Financial Statements. The assumed return on plan assets is based on OGE Energy's expectation of the long-term return on the plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and an increase in discount rates will reduce funding requirements to the pension plan. The following table indicates the sensitivity of OGE Energy's pension plan funded status to these variables.

 
  Change
  Impact on Funded
Status

  Portion of Impact
Allocated to Enogex

Actual plan asset returns   +/- 5 percent   +/- $26.0 million   +/- $2.1 million
Discount rate   +/- 0.25 percent   +/- $19.5 million   +/- $1.7 million
Contributions   + $10.0 million   + $10.0 million   + $10.0 million
Expected long-term return on plan assets   +/- 1 percent   None   None

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    Impairment of Assets

        Management assesses potential impairments of assets or asset groups when there is evidence that events or changes in circumstances require an analysis of the recoverability of an asset or asset group. For purposes of recognition and measurement of an impairment loss, a long-lived asset or assets shall be grouped with other assets and liabilities at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Estimates of future cash flows used to test the recoverability of a long-lived asset or asset group shall include only the future cash flows (cash inflows less associated cash outflows) that are directly associated with and that are expected to arise as a direct result of the use and eventual disposition of the asset or asset group. The fair value of these assets is based on third-party evaluations, prices for similar assets, historical data and projected cash flows. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset. Management expects to continue to evaluate the strategic fit and financial performance of each of Enogex's assets in an effort to ensure a proper economic allocation of resources. The magnitude and timing of any potential impairment or gain on the disposition of any assets have not been included in the 2007 assumptions and considerations.

    Commitments and Contingencies

        In the normal course of business, we and Enogex are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies and income tax related items. Management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, we or Enogex have incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the consolidated financial statements.

        Except as disclosed otherwise in this prospectus, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on our or Enogex's consolidated financial condition, results of operations or cash flows. See Notes 13 and 14 of Notes to Consolidated Financial Statements and the information under the caption "Business—Legal Proceedings" below.

Hedging Policies

        Enogex engages in cash flow hedge transactions to manage commodity risk. Enogex may hedge its forward exposure to manage the impact of changes in commodity prices. Hedges of anticipated transactions are documented as cash flow hedges pursuant to SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and are executed based upon management-established price targets. During 2004 and 2005, Enogex utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas and certain types of NGL hedges. During 2006, Enogex utilized hedge accounting under SFAS No. 133 to manage commodity exposure for contractual length and operational storage natural gas, keep-whole natural gas, NGL hedges and certain transportation hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. Enogex engages in cash flow and fair value hedge transactions to modify the rate composition of the debt portfolio. During 2005 and 2006, Enogex did not enter into any interest rate swap agreements.

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    Operating Revenues

        Operating revenues for gathering, processing, transportation and storage services are recorded each month based on the current month's estimated volumes, contracted prices (considering current commodity prices), historical seasonal fluctuations and any known adjustments. The estimates are reversed in the following month and customers are billed on actual volumes and contracted prices. Gas sales are calculated on current-month nominations and contracted prices. Operating revenues associated with the production of NGLs are estimated based on current-month estimated production and contracted prices. These amounts are reversed in the following month and the customers are billed on actual production and contracted prices. Estimated operating revenues are reflected in Accounts Receivable, Net on the consolidated balance sheets and in Operating Revenues on the consolidated statements of income.

    Natural Gas Purchases

        Estimates for gas purchases are based on sales volumes and contracted purchase prices. Estimated gas purchases are included in Accounts Payable on the consolidated balance sheets and in Cost of Goods Sold on the consolidated statements of income.

    Energy Purchase and Sale Contracts

        OERI's activities include the marketing and hedging of natural gas and NGLs. The vast majority of these contracts expire within three years, which is when the cash aspect of the transactions will be realized. A substantial portion of these contracts qualify as derivatives under SFAS No. 133 and are marked-to-market with offsetting gains and losses recorded in earnings. In nearly all cases, independent market prices are obtained and compared to the values used for this mark-to-market valuation, and an oversight group outside of the marketing organization monitors all modeling methodologies and assumptions. The recorded value of the energy contracts may change significantly in the future as the market price for the commodity changes, but the value is still subject to the risk loss limitations provided under our risk policies. Management utilizes models to estimate the fair value of energy contracts including derivatives that do not have an independent market price. At December 31, 2006, Enogex's unrealized mark-to-market gains were approximately $31.2 million, which included approximately $0.5 million of unrealized mark-to-market gains that were calculated utilizing models. At December 31, 2006, a price movement of 1.0% for prices verified by independent parties would result in changes in unrealized mark-to-market gains of less than $0.1 million and a price movement of 5.0% on model-based prices would result in changes in unrealized mark-to-market gains of approximately $0.1 million. Energy contracts are presented in Price Risk Management assets, liabilities or against the brokerage deposits in Other Current Assets on the consolidated balance sheets and in Operating Revenues on the consolidated statements of income.

    Natural Gas Inventory

        Natural gas inventory is held by the transportation and storage and marketing businesses. The transportation and storage business maintains natural gas inventory to provide operational support for Enogex's pipeline deliveries. In addition, as part of its recurring buy and sell activity, OERI injects and withdraws natural gas in to and out of inventory under the terms of its storage capacity contracts. In order to mitigate market price exposures, both businesses enter into contracts or hedging instruments to protect the cash flows associated with its inventory. During 2004, 2005 and 2006, OERI elected not to designate inventory hedging contracts as fair value or cash flow hedges under SFAS No. 133. The fair value of the hedging instruments is recorded on the books of OERI as Price Risk Management assets, liabilities or against the brokerage deposits in Other Current Assets with an offsetting gain or loss recorded in current earnings. All natural gas inventory held by Enogex is recorded at the lower of cost or market. During 2006, Enogex recorded write-downs to market value related to natural gas

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storage inventory of approximately $18.7 million. The amount of Enogex's natural gas inventory was approximately $35.9 million and $35.7 million at December 31, 2006 and 2005, respectively. Natural gas storage inventory is presented in Natural Gas Inventories on the consolidated balance sheets and in Cost of Goods Sold on the consolidated statements of income.

    Allowance for Uncollectible Accounts Receivable

        The allowance for uncollectible accounts receivable is calculated based on outstanding accounts receivable balances over 180 days old. In addition, other outstanding accounts receivable balances less than 180 days old are reserved on a case-by-case basis when management believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable, Net on the consolidated balance sheets and is included in Other Operation and Maintenance Expenses on the consolidated statements of income. The allowance for Enogex's uncollectible accounts receivable was approximately $1.1 million and $1.2 million at December 31, 2006 and 2005, respectively.

    Accounting Pronouncements

        See Notes 2 and 3 of Notes to Consolidated Financial Statements for a discussion of recent accounting pronouncements that are applicable to us and Enogex.

Quantitative and Qualitative Disclosures About Market Risk

        Market risks are, in most cases, risks that are actively traded in a marketplace and have been well studied in regards to quantification. Market risks include, but are not limited to, changes in commodity prices, commodity price volatilities and interest rates. Enogex is exposed to commodity price and commodity price volatility risks in its operations. Enogex's exposure to changes in interest rates relates primarily to short-term variable-rate debt, interest rate swap agreements and commercial paper. Enogex engages in price risk management activities for both trading and non-trading purposes.

    Risk Committee and Oversight

        Management monitors market risks using a risk committee structure. The Risk Oversight Committee of the partnership's general partner, which consists primarily of corporate officers, is responsible for the overall development, implementation and enforcement of strategies and policies for all risk management activities. This committee's emphasis is a holistic perspective of risk measurement and policies targeting our overall financial performance. The Risk Oversight Committee is authorized by, and will report quarterly to, the audit committee of the partnership's general partner.

        The partnership's general partner also has a Corporate Risk Management Department led by its Chief Risk Officer. This group, in conjunction with the aforementioned committees, is responsible for establishing and enforcing the risk policies.

    Risk Policies

        Management utilizes risk policies to control the amount of market risk exposure. These policies are designed to provide the audit committee and senior executives of the partnership's general partner with confidence that the risks taken on by our and Enogex's business activities are in accordance with their expectations for financial returns and that the approved policies and controls related to risk management are being followed. Some of the measures in these policies include value-at-risk, or VaR, limits, position limits, tenor limits and stop loss limits.

127


        Enogex's price risk management assets and liabilities as of September 30, 2007 were as follows:

<
 
  Commodity
  Notional Volume
(MMBtu)

  Maturity
  Fair Value
 
 
  (dollars in millions)

 
Trading                    

Price Risk Management Assets

 

 

 

 

 

 

 

 

 

 
 
Physical Purchases

 

Natural Gas

 

8.3

 

2007

 

$

0.3

 
  Physical Purchases   Natural Gas   6.4   2008     0.2  
               
 
    Total Physical Purchases                 0.5  
               
 
 
Physical Sales

 

Natural Gas

 

19.8

 

2007

 

 

2.9

 
  Physical Sales   Natural Gas   17.9   2008     2.8  
               
 
    Total Physical Sales                 5.7  
               
 
 
Short Physical Options

 

Natural Gas

 

9.3

 

2007

 

 

0.8

 
  Short Physical Options   Natural Gas   29.2   2008     1.3  
               
 
    Total Short Physical Options                 2.1