S-1 1 d526933ds1.htm FORM S-1 Form S-1
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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MAY 9, 2013

Registration No. 333-          

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

QEP Midstream Partners, LP

(Exact name of Registrant as Specified in Its Charter)

 

 

 

Delaware   4922   80-0918184

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

1050 17th Street, Suite 500

Denver, Colorado 80265

(303) 672-6900

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

 

 

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

1050 17th Street, Suite 500

Denver, Colorado 80265

(303) 672-6900

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

Michael E. Dillard

Sean T. Wheeler

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

Jeffery K. Malonson

Douglas E. McWilliams

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.    ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) 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.    ¨

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.    ¨

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.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x   (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of
Securities to be Registered
  Proposed
Maximum
Aggregate
Offering Price(1)(2)
  Amount of
Registration Fee

Common units representing limited partner interests

  $400,000,000   $54,560

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933.

 

 

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 said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not 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 jurisdiction where the offer or sale is not permitted.

 

PROSPECTUS    SUBJECT TO COMPLETION, DATED MAY 9, 2013  

QEP Midstream Partners, LP

Common Units

Representing Limited Partner Interests

 

 

This is an initial public offering of common units representing limited partner interests of QEP Midstream Partners, LP. We were recently formed by QEP Resources, Inc., or QEP. We are offering                     common units in this offering. We expect that the initial public offering price will be between $         and $         per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “QEPM.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.

 

 

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:

 

 

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.

 

Because of the natural decline in production from existing wells in our areas of operation, our success depends, in part, on producers replacing declining production and also on our ability to secure new sources of natural gas and crude oil. Any decrease in the volumes of natural gas or crude oil that we gather could adversely affect our business and operating results.

 

Natural gas and crude oil prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and crude oil relative to one another, could adversely affect our cash flow and our ability to make cash distributions to our unitholders.

 

Our general partner and its affiliates, including QEP, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over QEP’s business decisions and operations, and QEP is under no obligation to adopt a business strategy that favors us.

 

Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our general partner without its consent.

 

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

 

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

 

       Per Common Unit      Total

Initial price to public

     $                  $            

Underwriting discounts and commissions(1)

     $                  $            

Proceeds, before expenses, to QEP Midstream Partners, LP

     $                  $            

(1) Excludes a structuring fee equal to     % of the gross proceeds of this offering payable to Wells Fargo Securities, LLC. Please read “Underwriting.”

We have granted the underwriters a 30-day option to purchase up to an additional                     common units from us at the initial public offering price, less the underwriting discount, commission and structuring fee if the underwriters sell more than                      common units in this offering.

None of the Securities and Exchange Commission, any state securities commission or any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about                 , 2013.

 

 

Wells Fargo Securities

Prospectus dated                 , 2013.


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[Cover art to come]

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Our Assets and Operations

     3   

Business Strategies

     5   

Competitive Strengths

     6   

Our Relationship with QEP Resources, Inc.

     6   

Our Emerging Growth Company Status

     8   

Risk Factors

     9   

Formation Transactions and Partnership Structure

     10   

Ownership and Organizational Structure of QEP Midstream Partners, LP

     11   

Management of QEP Midstream Partners, LP

     12   

Principal Executive Offices and Internet Address

     12   

Summary of Conflicts of Interest and Duties

     12   

THE OFFERING

     14   

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     19   

RISK FACTORS

     22   

Risks Related to Our Business

     22   

Risks Inherent in an Investment in Us

     41   

Tax Risks

     50   

USE OF PROCEEDS

     55   

CAPITALIZATION

     56   

DILUTION

     57   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     58   

General

     58   

Our Minimum Quarterly Distribution

     60   

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012

     62   

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2014

     64   

Assumptions and Considerations

     67   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     72   

Distributions of Available Cash

     72   

Operating Surplus and Capital Surplus

     73   

Capital Expenditures

     75   

Subordinated Units and Subordination Period

     75   

Distributions of Available Cash from Operating Surplus During the Subordination Period

     77   

Distributions of Available Cash from Operating Surplus After the Subordination Period

     77   

General Partner Interest and Incentive Distribution Rights

     78   

Percentage Allocations of Available Cash from Operating Surplus

     78   

General Partner’s Right to Reset Incentive Distribution Levels

     79   

Distributions from Capital Surplus

     81   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     82   

Distributions of Cash Upon Liquidation

     83   

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

     86   

Non-GAAP Financial Measures

     88   

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

     91   

Overview

     91   

Our Operations

     91   

How We Evaluate Our Business

     92   

General Trends and Outlook

     93   

Factors Affecting the Comparability of Our Financial Results

     95   

Results of Operations

     96   


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Liquidity and Capital Resources

     98   

Off-Balance Sheet Arrangements

     100   

Credit Risk

     100   

Contractual Cash Obligations and Other Commitments

     101   

Critical Accounting Policies and Estimates

     101   

Quantitative and Qualitative Disclosures About Market Risk

     103   

INDUSTRY OVERVIEW

     104   

General

     104   

Natural Gas Midstream Services

     105   

Crude Oil Gathering and Transportation

     106   

Contractual Arrangements

     107   

U.S. Natural Gas Fundamentals

     108   

BUSINESS

     110   

Overview

     110   

Business Strategies

     111   

Competitive Strengths

     111   

Our Assets and Operations

     112   

Our Relationship with QEP Resources, Inc.

     125   

Competition

     127   

Seasonality

     127   

Insurance

     127   

Safety and Maintenance

     128   

Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service

     130   

Environmental Matters

     133   

Title to Properties and Permits

     139   

Employees

     140   

Legal Proceedings

     140   

MANAGEMENT

     142   

Management of QEP Midstream Partners, LP

     142   

Directors and Executive Officers of QEP Midstream Partners GP, LLC

     143   

Board Leadership Structure

     145   

Board Role in Risk Oversight

     145   

Executive Compensation

     145   

Long-Term Incentive Plan

     146   

Other Policies

     148   

Director Compensation

     149   

SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     150   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     151   

Distributions and Payments to Our General Partner and Its Affiliates

     151   

Agreements Governing the Transactions

     152   

Other Agreements with QEP and Related Parties

     154   

Procedures for Review, Approval and Ratification of Related Person Transactions

     154   

CONFLICTS OF INTEREST AND DUTIES

     156   

Conflicts of Interest

     156   

Duties of the General Partner

     161   

DESCRIPTION OF THE COMMON UNITS

     165   

The Units

     165   

Transfer Agent and Registrar

     165   

Transfer of Common Units

     165   

OUR PARTNERSHIP AGREEMENT

     167   

Organization and Duration

     167   

Purpose

     167   

Capital Contributions

     167   

 

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Voting Rights

     167   

Limited Liability

     169   

Issuance of Additional Securities

     170   

Amendment of Our Partnership Agreement

     170   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     172   

Termination and Dissolution

     173   

Liquidation and Distribution of Proceeds

     173   

Withdrawal or Removal of Our General Partner

     173   

Transfer of General Partner Interest

     175   

Transfer of Ownership Interests in Our General Partner

     175   

Transfer of Incentive Distribution Rights

     175   

Change of Management Provisions

     175   

Limited Call Right

     175   

Redemption of Ineligible Holders

     176   

Meetings; Voting

     176   

Status as Limited Partner

     177   

Indemnification

     177   

Reimbursement of Expenses

     178   

Books and Reports

     178   

Right to Inspect Our Books and Records

     178   

Registration Rights

     178   

Exclusive Forum

     179   

UNITS ELIGIBLE FOR FUTURE SALE

     180   

Rule 144

     180   

Our Partnership Agreement and Registration Rights

     180   

Lock-Up Agreements

     181   

Registration Statement on Form S-8

     181   

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

     182   

Partnership Status

     183   

Limited Partner Status

     184   

Tax Consequences of Unit Ownership

     184   

Tax Treatment of Operations

     190   

Disposition of Common Units

     191   

Uniformity of Units

     194   

Tax-Exempt Organizations and Other Investors

     194   

Administrative Matters

     195   

Recent Legislative Developments

     198   

State, Local, Foreign and Other Tax Considerations

     198   

INVESTMENT IN QEP MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

     200   

UNDERWRITING

     202   

Option to Purchase Additional Common Units

     202   

Discounts

     202   

Indemnification of Underwriters

     203   

Lock-Up Agreements

     203   

Electronic Distribution

     204   

New York Stock Exchange

     204   

Stabilization

     204   

Discretionary Accounts

     205   

Pricing of This Offering

     205   

Relationships

     205   

Sales Outside the United States

     205   

 

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VALIDITY OF THE COMMON UNITS

     207   

EXPERTS

     207   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     207   

FORWARD-LOOKING STATEMENTS

     208   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF QEP MIDSTREAM PARTNERS, LP

     A-1   

APPENDIX B GLOSSARY OF TERMS

     B-1   

 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor any of the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. When you make a decision about whether to invest in our common units, you should not rely upon any information other than the information in this prospectus and any free writing prospectus. Neither the delivery of this prospectus nor the sale of our common units means that information contained in this prospectus is correct after the date of this prospectus. 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.

Through and including                     , 2013 (25 days after the commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This delivery is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to their unsold allotments or subscriptions.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

 

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Industry and Market Data

The data included in this prospectus regarding the midstream natural gas and crude oil industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is reasonably accurate and complete.

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma combined financial statements and related notes included elsewhere in this prospectus, before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (1) an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional common units. You should read “Risk Factors” beginning on page 22 for more information about important factors that you should consider before purchasing our common units.

Unless the context otherwise requires, references in this prospectus to “QEP Midstream Partners, LP,” “our partnership,” “we,” “our,” “us,” or like terms on a historical basis refer to the assets that QEP (as defined below) is contributing to us in connection with this offering. These assets include a 100% interest in QEP Midstream Partners Operating, LLC, or QEP Operating, which will own (i) a 100% interest in each of (a) Green River Gathering, LLC, or Green River Gathering, (b) Rendezvous Pipeline Company, L.L.C., or Rendezvous Pipeline, (c) Vermillion Gathering, LLC, or Vermillion Gathering, and (d) Williston Gathering, LLC, or Williston Gathering, (ii) a 78% interest in Rendezvous Gas Services, L.L.C., or Rendezvous Gas, and (iii) a 50% interest in Three Rivers Gathering, L.L.C., or Three Rivers Gathering. When used in the present tense or prospectively, these terms refer to QEP Midstream Partners, LP and its subsidiaries, including QEP Operating. References to “our general partner” refer to QEP Midstream Partners GP, LLC. References to “QEP” refer collectively to QEP Resources, Inc. and its subsidiaries, other than us, our subsidiaries and our general partner. While we will only own (i) a 78% interest in Rendezvous Gas and (ii) a 50% interest in Three Rivers Gathering, in each case through QEP Operating, we refer to the assets owned by each of these entities as our assets. Unless specifically stated otherwise, historical financial and operating data is shown on a pro forma basis to reflect the assets that will be contributed to the Partnership. We have provided definitions for some of the terms we use to describe our business and industry in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

QEP Midstream Partners, LP

Overview

We are a limited partnership recently formed by QEP Resources, Inc. (NYSE: QEP) to own, operate, acquire and develop midstream energy assets. Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota, which are currently among the most economic and active drilling regions in the United States. As of and for the year ended December 31, 2012, our gathering systems had 1,475 miles of pipeline and an average gross throughput of 1.8 million MMBtu/d of natural gas and 18,224 Bbls/d of crude oil. Our customers are some of the largest natural gas producers in the Rocky Mountain region, including QEP, Anadarko Petroleum Corporation (Anadarko), EOG Resources, Inc. (EOG), Questar Corporation (Questar) and Ultra Resources, Inc. (Ultra).

We provide all of our gathering services through fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Approximately 85% of our revenues are generated pursuant to contracts with remaining terms in excess of seven years, including 71% of our revenues that are generated pursuant to “life-of-reserves” contracts. In addition to our fee-based gathering services, we generate approximately 6% of our revenue through the sale of condensate volumes that we collect on our gathering systems. For the year ended December 31, 2012, approximately 40% of our natural gas gathering volumes and approximately 45% of our crude oil volumes were comprised of production owned by QEP, making QEP our largest customer.

 


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We have secured significant acreage dedications from several of our largest customers, including QEP. We believe that drilling activity on acreage dedicated to us should maintain or increase our existing throughput levels and offset the natural production declines of the wells currently connected to our gathering systems. Pursuant to the terms of those agreements, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering contract and located within the dedicated acreage as our gathering systems currently exist and as they are expanded to connect to additional wells.

We believe that one of our principal strengths is our relationship with QEP. QEP is engaged in crude oil and natural gas exploration and production (E&P) activities, as well as midstream activities related to its E&P operations. For the year ended December 31, 2012, QEP reported 3.9 Tcfe of total net proved reserves and total net production of 319.2 Bcfe, representing a 9% and a 16% increase, respectively, in proved reserves and production as compared to the year ended December 31, 2011. We believe this relationship will provide us with the opportunity to increase throughput volumes from QEP production in areas where we have gathering systems.

To help facilitate the growth of its E&P operations, QEP invested over $1.1 billion in midstream infrastructure from 2007 through 2012. Following the completion of this offering and the transactions contemplated thereby, QEP will continue to own a substantial and growing portfolio of other midstream assets. QEP intends for us to be the primary growth vehicle for its midstream business. As a result, we believe QEP will offer us the opportunity to purchase additional midstream assets from it, although it is under no obligation to offer to sell us additional assets. Please read “— Our Relationship with QEP Resources, Inc.” for additional information with respect to QEP’s portfolio of midstream assets.

For the year ended December 31, 2012, we generated $126.7 million of revenue, $55.8 million of net income attributable to us and $86.0 million of Adjusted EBITDA. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income attributable to our Predecessor or us and cash flow provided by operating activities, the most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States, or GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

 

 

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Our Assets and Operations

Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines. The following table provides information regarding our assets by system as of December 31, 2012:

 

Gathering System

 

Asset Type

  Length
(miles)
    Receipt
Points
    Compression
(horsepower)
    Throughput
Capacity

(MMcf/d) (1)
    Average  Daily
Throughput

(Thousand
MMBtu/d)
(1)
 

Green River System

           

Green River Gathering

  Gas Gathering     405        307        41,053        737        551   
  Oil Gathering     61        93               7,137 (2)      3,750 (2) 
  Water Gathering     81        93               21,990 (3)      10,925 (3) 
  Oil Transmission(4)     60        6               40,800 (2)      11,711 (2) 

Rendezvous Gas(5)

  Gas Gathering     309        3        7,800        1,032        663   

Rendezvous Pipeline (4)

  Gas Transmission     21        1               460        274   

Vermillion Gathering System

  Gas Gathering     454        503        23,197        206        142   

Three Rivers Gathering System(6)

  Gas Gathering     50        8        4,735        212        140   

Williston Gathering System

  Gas Gathering     17        24        239        3        1   
  Oil Gathering     17        24               7,000 (2)      2,763 (2) 
   

 

 

   

 

 

   

 

 

     

Total

      1,475        1,062        77,024       
   

 

 

   

 

 

   

 

 

     

 

(1) Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2012.
(2) Capacity and throughput measured in barrels of crude oil per day.
(3) Capacity and throughput measured in barrels of water per day.
(4) FERC-regulated pipeline.
(5) Our ownership interest in Rendezvous Gas is 78%.
(6) Our ownership interest in Three Rivers Gathering is 50%.

Green River System

Our Green River System, located in western Wyoming, consists of three complimentary systems owned by Green River Gathering, Rendezvous Gas and Rendezvous Pipeline and gathers natural gas production from the Pinedale, Jonah and Moxa Arch fields. In addition to gathering natural gas, the system also (i) gathers and stabilizes crude oil production from the Pinedale Field, (ii) transports the stabilized crude oil to an interstate pipeline interconnect, and (iii) gathers and handles produced and flowback water associated with well completion activities in the Pinedale Field.

Green River Gathering

The Green River Gathering assets are comprised of 405 miles of natural gas gathering pipelines, 61 miles of crude oil gathering pipelines, 81 miles of water gathering pipelines and a 60-mile, FERC-regulated crude oil pipeline located in the Green River Basin. The Green River Gathering assets are primarily supported by “life-of-reserves” and long-term, fee-based gathering agreements. The primary customers on these assets include QEP, Questar, Ultra, and Anadarko. The assets have a current aggregate natural gas throughput capacity of 737 MMcf/d and had average gross natural gas throughput of 551 thousand MMBtu/d for the year ended December 31, 2012. These assets also had average gross gathering throughput of 3,750 Bbls/d of oil and 10,925 Bbls/d of water for the year ended December 31, 2012. Our FERC-regulated crude oil pipeline, which includes third-party, crude oil volumes not gathered on our system, had average gross throughput of 11,711 Bbls/d for the year ended December 31, 2012.

Rendezvous Gas

Rendezvous Gas is a joint venture between QEP and Western Gas Partners, LP (Western Gas) that was formed to own and operate the infrastructure that transports gas from the Pinedale and Jonah fields to

 

 

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several re-delivery points, including natural gas processing facilities that are owned by QEP or Western Gas. The Rendezvous Gas assets consist of three parallel, 103-mile high-pressure natural gas pipelines, with 1,032 MMcf/d of throughput capacity and 7,800 bhp of gas compression. Rendezvous Gas entered into separate agreements with QEP and Western Gas to gather the natural gas dedicated to each party from producers within an area of mutual interest. Average gross throughput on the Rendezvous Gas system was 663 thousand MMBtu/d for the year ended December 31, 2012.

Rendezvous Pipeline

Rendezvous Pipeline’s sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEP’s Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 460 MMcf/d and had an average gross throughput of 274 thousand MMBtu/d for the year ended December 31, 2012. The capacity on the Rendezvous Pipeline system is contracted under long-term transportation contracts with remaining terms of more than nine years.

Vermillion Gathering System

The Vermillion Gathering System consists of gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah, which, when combined, include 454 miles of low-pressure, gas gathering pipelines and 23,197 bhp of gas compression. The Vermillion Gathering System is primarily supported by “life-of-reserves” and long-term, fee-based gas gathering agreements with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. The primary customers on our Vermillion Gathering System include Questar, Samson Resources Corporation (Samson Resources), QEP and Chevron USA, Inc. (Chevron). Approximately 70% of 2012 throughput volumes on the Vermillion Gathering System were gathered pursuant to “life-of-reserves” contracts and contracts with remaining terms of more than five years. The Vermillion Gathering System has combined total throughput capacity of 206 MMcf/d and had average gross throughput of 142 thousand MMBtu/d for the year ended December 31, 2012.

Three Rivers Gathering System

Three Rivers Gathering is a joint venture between QEP and Ute Energy Midstream Holdings, LLC (Ute Energy) that was formed to transport natural gas gathered by Uintah Basin Field Services, L.L.C., an indirectly owned subsidiary of QEP (Uintah Basin Field Services), and other third-party volumes to gas processing facilities owned by QEP and third parties. The Three Rivers Gathering System consists of gas gathering assets located in the Uinta Basin in northeast Utah, including approximately 50 miles of gathering pipeline and 4,735 bhp of gas compression. The Three Rivers Gathering System is primarily supported by long-term, fee-based gas gathering agreements with minimum volume commitments. The system has aggregate minimum volume commitments of 212 thousand MMBtu/d from three different producers through 2018. The primary customers on our Three Rivers Gathering System include Bill Barrett Corporation (Bill Barrett), XTO Energy, Inc. (XTO), Anadarko and QEP. The Three Rivers Gathering System has total throughput capacity of 212 MMcf/d and had average gross throughput of 140 thousand MMBtu/d for the year ended December 31, 2012.

Williston Gathering System

The Williston Gathering System is a crude oil and natural gas gathering system located in the Williston Basin in McLean County, North Dakota. The Williston Gathering System includes 17 miles of gas gathering pipelines, 17 miles of oil gathering pipelines, 239 bhp of gas compression, and a crude oil and natural gas handling facility, located primarily on the Fort Berthold Indian Reservation. The Williston Gathering System is primarily supported by long-term, fee-based, crude oil and gas gathering agreements with minimum

 

 

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volume commitments. The system has aggregate minimum volume commitments of approximately 5,600 Bbls/d of crude oil and five thousand MMBtu/d of natural gas from one producer through 2026. QEP and Marathon Oil Company are currently the only customers on our Williston Gathering System. The Williston Gathering System has total crude oil throughput capacity of 7,000 Bbls/d and had average gross throughput of 2,763 Bbls/d of crude oil for the year ended December 31, 2012.

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and cash flows. We expect to achieve this objective by pursuing the following business strategies:

 

   

Pursuing acquisitions from QEP.    We intend to seek opportunities to expand our operations primarily through acquisitions from QEP, including the following:

 

   

QEP’s portfolio of retained midstream assets, which include natural gas gathering, processing, and treating assets; and

 

   

Expansion projects that QEP undertakes in the future as it builds additional midstream assets in support of its E&P operations.

While we will review acquisition opportunities from third parties as they become available, we expect that most of our significant opportunities over the next several years will be sourced from QEP. Based on QEP’s significant ownership interest in us following this offering, we believe QEP will offer us the opportunity to purchase additional midstream assets from it, as well as to jointly pursue midstream acquisitions with it. QEP is under no obligation, however, to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any such additional assets or to pursue any such joint acquisitions. For a description of QEP’s retained midstream asset portfolio, please read “— Our Relationship with QEP Resources, Inc.”

 

   

Leveraging our relationship with QEP to pursue economically attractive organic growth opportunities.    The acreage dedicated to our assets, coupled with QEP’s economic relationship with us, provides a platform for future organic growth from our existing assets. As QEP and other producers execute their drilling plans within our areas of operation, we expect that we will capture additional production volumes on our systems.

 

   

Attracting additional third-party volumes to our systems.    We actively market our midstream services to, and pursue strategic relationships with, third-party producers in order to attract additional volumes to our existing systems and to develop new systems in areas where we do not currently operate. We believe that the location of our current systems and their direct connection to multiple interstate pipelines provides us with a competitive advantage that will attract additional third-party volumes in the future.

 

   

Diversifying our asset base by pursuing acquisition and development opportunities in new geographic areas.    In addition to our existing areas of operations, we expect to diversify our midstream business and expand our platform for future growth through acquisition and greenfield development opportunities in geographic regions where neither QEP nor we currently operate.

 

   

Minimizing direct commodity price exposure.    We intend to maintain our focus on providing midstream services under fee-based agreements. Although we currently have commodity price exposure associated with our condensate sales on our Green River and Vermillion gathering systems, we expect to have agreements in place with QEP with primary terms of five years to sell these volumes at a fixed price. We intend to continue to limit our direct exposure to commodity price risk and to promote cash flow stability by utilizing fee-based contracts and fixed-price crude oil and condensate sales agreements.

 

 

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Competitive Strengths

We believe that we are well-positioned to successfully execute our business strategies by capitalizing on the following competitive strengths:

 

   

Our affiliation with QEP.    As the owner of our general partner, all of our incentive distribution rights, or IDRs, and a     % limited partner interest in us, we believe QEP is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.

 

   

Acquisition opportunities.    After the closing of this offering, QEP will continue to own a substantial and growing portfolio of midstream assets, and we believe QEP will offer us the opportunity to purchase some or all of those midstream assets in the future, although it is not obligated to do so.

 

   

QEP.    QEP is one of the largest natural gas producers in the Rocky Mountain region with 3.9 Tcfe of total net proved reserves as of December 31, 2012. QEP serves as the operator for 3.8 Tcfe of gross proved reserves, which are dedicated to our gathering systems. QEP is our largest customer and is an anchor tenant on a number of our gathering systems.

 

   

Acreage Dedication.    QEP has dedicated approximately 193,000 gross acres to our existing systems, which we believe contain significant oil and natural gas reserves. We believe that drilling activity on acreage that QEP has dedicated to us will increase the gathering and transmission volumes on our systems.

 

   

Strategically located asset base with direct access to multiple interstate pipelines.    The majority of our assets are located in, or are within close proximity to, the Green River, Uinta and Williston Basins, which are among the most economic and active drilling regions in the United States. In addition, all of our assets have access to major natural gas and crude oil markets via direct connections to interstate and intrastate pipelines and rail loading facilities. Our direct connections allow producers to select from various markets to sell oil and natural gas in order to take advantage of market differentials. In addition, our direct connections to multiple interstate pipelines reduce producers’ transportation expense by allowing them to avoid additional tariffs that they would otherwise incur if they utilized several interconnections to transport their oil and natural gas production to a specific interstate pipeline.

 

   

Stable and predictable cash flows.    Substantially all of our revenues are generated under fee-based contracts. This economic model enhances the stability of our cash flows and minimizes our direct exposure to commodity price risk.

 

   

Experienced management and operating teams.    Our executive management team has an average of over 25 years of experience in building, acquiring, financing and managing large-scale midstream and other energy assets. In addition, we employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large-scale, complex midstream energy assets.

 

   

Financial flexibility and strong capital structure.    Following this offering, we expect to have no debt and borrowing capacity of $         million under our new $         million revolving credit facility. We believe that our borrowing capacity and our ability to access debt and equity capital markets will provide us with the financial flexibility necessary to achieve our business strategy.

Our Relationship with QEP Resources, Inc.

One of our principal strengths is our relationship with QEP, a leading independent natural gas and crude oil exploration and production company. QEP is a holding company with three major lines of business — natural gas and oil exploration and production, midstream field services, and energy marketing — which are conducted through three principal subsidiaries:

 

   

QEP Energy Company acquires, explores for, develops and produces natural gas, crude oil and NGLs;

 

 

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QEP Field Services Company, or QEP Field Services, provides midstream field services, including natural gas gathering, processing, compression and treating services for affiliates and third parties; and

 

   

QEP Marketing Company markets QEP and third-party natural gas and crude oil, and owns and operates an underground natural gas storage reservoir.

QEP is a leader among exploration and production companies in several of the most economic natural gas and crude oil basins in North America. QEP had approximately 1.9 million total net leasehold acres as of December 31, 2012, of which approximately 1 million net acres were located in Colorado, North Dakota, Utah and Wyoming. For the year ended December 31, 2012, QEP reported total net production of 319.2 Bcfe and total net proved reserves of 3.9 Tcfe, representing a 16% and a 9% increase, respectively, in production and proved reserves as compared to the year ended December 31, 2011.

The following tables provide information regarding QEP’s remaining midstream assets after this offering:

Gathering

 

Gathering System

 

Primary
Location

  Length
(miles)
    Receipt
Points
    Compression
(horsepower)
    Throughput
Capacity

(MMcf/d) (1)
    Average  Daily
Throughput

(Thousand
MMBtu/d)
(1)
 

Uinta Basin Gathering System

  Uinta Basin     609        1,946        55,646        299        215   

Uintah Basin Field Services(2)

  Uinta Basin     78        21        5,360        26        13   

Haynesville Gathering System

  Haynesville Shale     200        230        7,360        2,000        323   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

      887        2,197        68,366        2,325        551   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2012.
(2) QEP’s ownership interest in Uintah Basin Field Services is 38%.

Processing/Treating/Fractionation

 

Asset

  

Primary
Location

  

Asset Type

  

Facility Type

   Throughput
Capacity

(MMcf/d) (1)
    Average  Daily
Throughput

(Thousand
MMBtu/d)
(1)
 

Black Fork Processing Complex

   Green River Basin    Processing   

Cryogenic /

Joule-Thomson

     835        485   
      Fractionation    Fractionator      15,000 (2)(3)      4,040 (2) 

Emigrant Trail Processing Plant

   Green River Basin    Processing    Cryogenic      55        30   

Vermillion Processing Plant(4)

   Southern Green River Basin    Processing    Cryogenic      43        38   

Uinta Basin Processing Complex

   Uinta Basin    Processing   

Cryogenic /

Refrigeration

     650 (5)      308   

Haynesville Gathering System

   Haynesville Shale    Treating    Treating      600        323   
           

 

 

   

Total

         Processing      1,583     
           

 

 

   
         Treating      600     
           

 

 

   
         Fractionation      15,000     
           

 

 

   

 

(1) Represents 100% of the capacity and throughput of the assets as of and for the year ended December 31, 2012.
(2) Throughput measured in barrels of NGL per day.
(3) Includes QEP’s 10,000 Bbls/d fractionator expansion that we expect to be operational in the third quarter of 2013.
(4) QEP’s ownership interest in the Vermillion Processing Plant is 71%.
(5) Throughput capacity includes volumes associated with the 150 MMcf/d Iron Horse II cryogenic processing plant that commenced operations in February 2013.

 

 

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We will enter into an omnibus agreement with QEP in connection with this offering. The omnibus agreement will address our payment of an annual amount to QEP for certain general and administrative services and QEP’s indemnification of us for certain matters, including environmental, contractual, title and tax matters. While not the result of arm’s-length negotiations, we believe the terms of the omnibus agreement with QEP will be generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions.”

While our relationship with QEP and its subsidiaries is a significant strength, it is also a source of potential conflicts. Additionally, we have no control over QEP’s business decisions and operations, and QEP is under no obligation to adopt a business strategy that favors us. Please read “Conflicts of Interest and Duties” and “Risk Factors — Risks Inherent in an Investment in Us — Our General Partner and Its Affiliates, Including QEP, Have Conflicts of Interest With Us and Limited Duties to Us and Our Unitholders, and They May Favor Their Own Interests to Our Detriment and that of Our Unitholders. Additionally, We Have No Control Over QEP’s Business Decisions and Operations, and QEP is Under No Obligation to Adopt a Business Strategy that Favors Us.”

Our Emerging Growth Company Status

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As long as a company is deemed an emerging growth company, it may take advantage of specified reduced reporting and other regulatory requirements that are generally unavailable to other public companies. These provisions include:

 

   

a requirement to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis included in an initial public offering registration statement;

 

   

an exemption to provide less than five years of selected financial data in an initial public offering registration statement;

 

   

an exemption from the auditor attestation requirement in the assessment of the emerging growth company’s internal controls over financial reporting;

 

   

an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies;

 

   

an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

   

reduced disclosure about the emerging growth company’s executive compensation arrangements pursuant to the rules applicable to smaller reporting companies; and

 

   

no requirement to seek non-binding advisory votes on executive compensation or golden parachute arrangements.

We may take advantage of any of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenues, (iii) the date on which we have more than $700 million in market value of our common units held by non-affiliates or (iv) the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period.

 

 

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We have elected to adopt the reduced disclosure requirements described above, except we have elected to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards (this election is irrevocable). As a result of these elections, the information that we provide in this prospectus may be different from the information you may receive from other public companies in which you hold equity interests.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units.

 

 

 

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Formation Transactions and Partnership Structure

At or prior to the closing of this offering the following transactions, which we refer to as the formation transactions, will occur:

 

   

QEP will convey its ownership interests in each of Green River Gathering, Vermillion Gathering, Williston Gathering, Rendezvous Gas, Rendezvous Pipeline and Three Rivers Gathering to QEP Operating as a capital contribution and in exchange for QEP Operating assuming $                 million of existing debt;

 

   

QEP will convey an interest in QEP Operating to our general partner as a capital contribution;

 

   

Our general partner will convey its interest in QEP Operating to us in exchange for (i) maintaining its 2% general partner interest in us, and (ii) our IDRs;

 

   

QEP will convey its remaining interest in QEP Operating to us in exchange for (i)                 common units, representing a     % limited partner interest in us, (ii)                 subordinated units, representing a     % limited partner interest in us, and (iii) the right to receive $         million in cash, a portion of which will be used to reimburse QEP for certain capital expenditures it incurred with respect to assets it contributed to us;

 

   

We will issue                  common units to the public, representing a      % limited partner interest in us;

 

   

We will enter into a new $         million credit facility; and

 

   

We will use the net proceeds from the offering as set forth under “Use of Proceeds.”

 

 

 

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Ownership and Organizational Structure of QEP Midstream Partners, LP

The following table and diagram illustrate our ownership and organizational structure after giving effect to the transactions described in “— Formation Transactions and Partnership Structure” and assume that the underwriters’ option to purchase additional common units is not exercised:

 

     Ownership
Interest
 

Public common units

         

QEP common units

         

QEP subordinated units

         

General partner units

     2.0
  

 

 

 

Total

     100.0
  

 

 

 

LOGO

 

 

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Management of QEP Midstream Partners, LP

We are managed and operated by the board of directors and executive officers of QEP Midstream Partners GP, LLC, our general partner. QEP is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange, or NYSE. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. All of the executive officers and many of the directors of our general partner also currently serve as officers of QEP. For more information about the directors and executive officers of our general partner, please read “Management — Directors and Executive Officers of QEP Midstream Partners GP, LLC.”

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by QEP or others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, including QEP, but we sometimes refer to these individuals in this prospectus as our employees.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1050 17th Street, Suite 500, Denver, Colorado 80265, and our telephone number is (303) 672-6900. Following the completion of this offering, our website will be located at www.                    .com and will be activated in connection with the closing of this offering. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (SEC) available, free of charge, through 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.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to the best interests of our partnership. However, because our general partner is a wholly owned subsidiary of QEP, the officers and directors of our general partner have a duty to manage the business of our general partner in a manner that is not adverse to the best interests of QEP. As a result of this relationship, 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 QEP, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Duties.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including QEP and its other subsidiaries, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement,

 

 

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and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of the General Partner” for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units and subordinated units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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THE OFFERING

 

Common units offered to the public

                 common units.

 

                   common units if the underwriters exercise in full their option to purchase additional common units from us.

 

Units outstanding after this offering

                 common units and                  subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own                  general partner units, representing a 2.0% general partner interest in us.

 

Use of proceeds

We expect to receive net proceeds of approximately $         million from the sale of common units offered by this prospectus based on the initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, estimated offering expenses and structuring fees. We intend to use the net proceeds as follows:

 

   

make a cash distribution to QEP of $         million, a portion of which will be used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to us;

 

   

distribute $         million to QEP Operating, which will use those funds to repay all $         million of its outstanding debt; and

 

   

pay revolving credit facility origination fees of $         million.

 

  The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be used to redeem from QEP a number of common units equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee.

 

Cash distributions

We intend to make a minimum quarterly distribution of $         per unit 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.

 

  For the quarter in which this offering closes, we will pay a prorated distribution on our units covering the period from the completion of this offering through                 , 2013, based on the actual length of that period.

 

  In general, we will pay any cash distributions we make each quarter in the following manner:

 

   

first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

 

 

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second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $         ; and

 

   

third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $        .

 

  If cash distributions to our unitholders exceed $         per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

  If we do not generate sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

 

  The amount of pro forma available cash generated during the year ended December 31, 2012 would have been sufficient to allow us to pay the minimum quarterly distribution on all of our common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest during those periods.

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions — Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2014” that we will have sufficient available cash to pay the aggregate minimum quarterly distribution of $         million on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2.0% interest for the twelve months ending June 30, 2014. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

QEP will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages.

 

 

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Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid at least (1) $         (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four quarter periods ending on or after                      , 2016 or (2) $         (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and the incentive distribution rights for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on our common units at that time.

 

  The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

 

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

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read “Units Eligible for Future Sale” and “Our 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, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders 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 66 2/3% 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, QEP will own an aggregate of     % of our common and subordinated units (or     % of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give QEP the ability to prevent the removal of our general partner. Please read “Our Partnership Agreement — Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner has

 

 

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the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “Our Partnership Agreement — Limited Call Right.”

 

Redemption of ineligible holders

Units held by persons who our general partner determines are not “citizenship eligible holders” or “rate eligible holders” will be subject to redemption. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate eligible holders are:

 

   

individuals or entities subject to U.S. federal income taxation on the income generated by us; or

 

   

entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are domestic individuals or entities subject to such taxation.

 

  We will have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not a citizenship eligible holder or a rate eligible holder or that has failed to certify or has falsely certified that such holder is a citizenship eligible holder or a rate eligible holder. The redemption price will be equal to the market price of the common units as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not a citizenship eligible holder will not be entitled to voting rights.

 

  Please read “Our Partnership Agreement — Redemption of Ineligible Holders.”

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, 2015, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $         per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $         per unit. Thereafter, the ratio of allocable

 

 

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taxable income to cash distributions to you could substantially increase. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”

 

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “QEPM.”

 

 

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

Our Predecessor consists of all of QEP’s gathering assets in the Green River, Uinta and Williston Basins, including (i) a 100% interest in each of Green River Gathering, Rendezvous Pipeline, Vermillion Gathering and Williston Gathering, (ii) a 78% interest in Rendezvous Gas, (iii) a 50% equity interest in Three Rivers Gathering, (iv) a 38% equity interest in Uintah Basin Field Services and (v) a 100% interest in all other QEP gathering assets and operations that QEP conducts in the Uinta Basin (referred to as the Uinta Basin Gathering System). The following table presents, in each case for the periods and as of the dates indicated, summary historical combined financial and operating data of our Predecessor and summary pro forma combined financial and operating data of QEP Midstream Partners, LP.

The summary historical combined financial and operating data of our Predecessor as of and for the years ended December 31, 2012 and 2011 are derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus.

The summary pro forma combined financial data presented in the following table as of and for the year ended December 31, 2012 are derived from the unaudited pro forma combined financial data included elsewhere in this prospectus. The pro forma combined financial data assumes that the transactions described under “—Formation Transactions and Partnership Structure” occurred as of January 1, 2012. These transactions primarily include, and the pro forma financial data give effect to, the following:

 

   

the contribution of (i) 100% of the ownership interests in each of Green River Gathering, Rendezvous Pipeline, Vermillion Gathering and Williston Gathering, (ii) a 78% interest in Rendezvous Gas, and (iii) a 50% equity interest in Three Rivers Gathering;

 

   

QEP’s retention of the Uinta Basin Gathering System and its 38% interest in Uintah Basin Field Services, which will not be contributed to us;

 

   

our entry into a new $         million revolving credit facility;

 

   

our entry into an omnibus agreement with QEP;

 

   

the issuance of                  common units and                  subordinated units; and

 

   

the application of the $         million in net proceeds from this offering as described in “Use of Proceeds.”

The pro forma combined financial data does not give effect to the estimated $2.5 million in incremental annual general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our Predecessor and the notes thereto and our unaudited pro forma combined financial statements and the notes thereto, in each case included elsewhere in this prospectus. Among other things, those historical and pro forma combined financial statements include more detailed information regarding the basis of presentation for the information in the following table. Our financial position, results of operations and cash flows could differ from those that would have resulted if we operate autonomously or as an entity independent of QEP in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

The following table presents Adjusted EBITDA, a financial measure that is not presented in accordance with generally accepted accounting principles in the United States, or GAAP. For a

 

 

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reconciliation of Adjusted EBITDA to net income attributable to our Predecessor and us and cash flows from operating activities, the most directly comparable financial measures calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.” For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Business.”

 

     QEP Midstream Partners, LP
Predecessor
    QEP Midstream
Partners, LP
Pro Forma
 
     Year Ended December 31,     Year Ended
December 31,
 
     2011     2012     2012  
     (in millions)  

Statement of Operations

      

Revenues

   $ 155.9      $ 161.4      $ 126.7   

Operating Expenses:

      

Gathering expense

     27.7        29.9        21.1   

General and administrative(1)

     15.3        19.4        14.5   

Taxes other than income taxes

     2.8        3.1        2.1   

Depreciation and amortization

     38.3        39.8        30.6   
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     84.1        92.2        68.3   
  

 

 

   

 

 

   

 

 

 

Operating income

     71.8        69.2        58.4   

Other income

     0.1        0.1        0.1   

Income from unconsolidated affiliates

     4.4        7.2        3.5   

Interest expense

     (12.8     (8.7     (2.5
  

 

 

   

 

 

   

 

 

 

Net income

     63.5        67.8        59.5   

Net income attributable to noncontrolling interest

     (3.2     (3.7     (3.7
  

 

 

   

 

 

   

 

 

 

Net income attributable to our Predecessor or us

   $ 60.3      $ 64.1      $ 55.8   
  

 

 

   

 

 

   

 

 

 

General partner’s interest in net income

      

Limited partner’s interest in net income

      

Common units

      

Subordinated units

      

Net income per limited partner unit

      

Common units

      

Subordinated units

      

Balance Sheet

      

Property, plant and equipment, net

   $ 629.1      $ 634.1      $ 503.9   

Total assets

     714.3        724.6        573.8   

Long-term debt to related party

     174.6        134.2          

Statement of Cash flows

      

Net cash provided by operating activities

   $ 97.5      $ 104.5     

Capital expenditures

     (28.6     (43.7  

Net cash used in investing activities

     (28.5     (43.4  

Net cash used in financing activities

     (68.0     (62.2  

 

 

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     QEP Midstream Partners, LP
Predecessor
    QEP Midstream
Partners, LP
Pro Forma
 
     Year Ended December 31,     Year Ended
December 31,
 
     2011     2012     2012  

Operating information

      

Natural gas throughput in millions of MMBtu

      

Gathering and transportation

     384.7        387.8        309.2   

Equity interest(2)

     34.4        27.5        25.7   
  

 

 

   

 

 

   

 

 

 

Total natural gas throughput

     419.1        415.3        334.9   

Throughput attributable to noncontrolling
interests(3)

     (14.3     (12.1     (12.1
  

 

 

   

 

 

   

 

 

 

Total throughput attributable to our Predecessor or us

     404.8        403.2        322.8   

Average gas gathering and transportation fee (per MMBtu)

   $ 0.30      $ 0.34      $ 0.32   

Crude oil and condensate gathering system throughput volumes (in MBbls)

     4,105.4        5,297.4        5,297.4   

Average oil and condensate gathering fee (per barrel)

   $ 1.89      $ 2.11      $ 2.11   

Non-GAAP Measures

      

Adjusted EBITDA (in millions)

   $ 109.6      $ 109.7      $ 86.0   

 

(1) Pro forma general and administrative expenses do not give effect to annual incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of being a publicly traded partnership. For more information regarding the general and administrative expense allocation, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Business — Operating Expenses — General and Administrative Expenses.”

 

(2) Includes our 50% share of gross volumes from Three Rivers Gathering and our 38% share of gross volumes from Uintah Basin Field Services.

 

(3) Includes the 22% noncontrolling interest in Rendezvous Gas.

 

 

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RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the 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 a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose part or all of your investment.

Risks Related to Our Business

We May Not Have Sufficient Cash from Operations Following the Establishment of Cash Reserves and Payment of Fees and Expenses, Including Cost Reimbursements to Our General Partner, to Enable Us to Pay the Minimum Quarterly Distribution, or Any Distribution, to Holders of Our Common and Subordinated Units.

In order to pay the minimum quarterly distribution of $         per unit per quarter, or $         per unit on an annualized basis, we will require available cash of approximately $         million per quarter, or $         million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

   

the volume of natural gas and oil we gather;

 

   

the level of production of oil and natural gas and the resultant market prices of oil, natural gas and NGLs;

 

   

damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third party pipelines or facilities upon which we rely for transportation services;

 

   

leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

 

   

prevailing economic and market conditions;

 

   

capacity charges and volumetric fees associated with our transportation services;

 

   

the level of competition from other midstream energy companies in our geographic markets;

 

   

the level of our operating, maintenance and general and administrative costs; and

 

   

regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

   

the level of capital expenditures we make;

 

   

the cost of acquisitions, if any;

 

   

our debt service requirements and other liabilities;

 

   

fluctuations in our working capital needs;

 

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our ability to borrow funds and access capital markets;

 

   

restrictions contained in our debt agreements;

 

   

the amount of cash reserves established by our general partner; and

 

   

other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The Assumptions Underlying the Forecast of Cash Available for Distribution that We Include in “Our 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.

The forecast 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 twelve months ending June 30, 2014. The financial forecast has been prepared by 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, including risks that expansion projects do not result in an increase in gathered volumes, 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 or subordinated units, in which event the market price of our common units may decline materially.

The Amount of Cash We Have Available for Distribution to Holders of Our Common and Subordinated Units Depends Primarily on Our Cash Flow Rather Than on Our Profitability, Which May Prevent Us from Making Distributions, Even During Periods in Which We Record Net Income.

The amount of cash we have available for distribution depends primarily upon our cash flow 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.

Because of the Natural Decline in Production from Existing Wells in Our Areas of Operation, Our Success Depends, in Part, on Producers Replacing Declining Production and Also on Our Ability to Secure New Sources of Natural Gas and Crude Oil. Any Decrease in the Volumes of Natural Gas or Crude Oil that We Gather Could Adversely Affect Our Business and Operating Results.

The natural gas and crude oil volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas and crude oil. The primary factors affecting our ability to obtain non-dedicated sources of natural gas and crude oil include (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

 

   

the availability and cost of capital;

 

   

prevailing and projected oil, natural gas and NGL prices;

 

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demand for oil, natural gas and NGLs;

 

   

levels of reserves;

 

   

geological considerations;

 

   

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

 

   

the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of oil and natural gas reserves. Drilling and production activity generally decreases as oil and natural gas prices decrease. Declines in oil and natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

Because of these and other factors, even if oil and natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

We Do Not Intend to Obtain Independent Evaluations of Oil and Natural Gas Reserves Connected to Our Gathering and Transportation Systems on a Regular or Ongoing Basis; Therefore, in the Future, Volumes of Oil and Natural Gas on Our Systems Could Be Less Than We Anticipate.

We do not intend to obtain independent evaluations of oil and natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of oil or natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our Success Depends on Drilling Activity and Our Ability to Attract and Maintain Customers in a Limited Number of Geographic Areas.

A significant portion of our assets is located in the Green River, Uinta and Williston Basins, and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows are significantly dependent upon the demand for our services in these areas. Due to our focus on these areas, an adverse development in oil or natural gas production from these areas would have a significantly greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Green River, Uinta or Williston Basins could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Natural Gas and Crude Oil Prices are Volatile, and a Change in These Prices in Absolute Terms, or an Adverse Change in the Prices of Natural Gas and Crude Oil Relative to One Another, Could Adversely Affect Our Cash Flow and Our Ability to Make Cash Distributions to Our Unitholders.

The markets for and prices of natural gas, crude oil and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

   

worldwide economic conditions;

 

   

worldwide political events, including actions taken by foreign oil and natural gas producing nations;

 

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worldwide weather events and conditions, including natural disasters and seasonal changes;

 

   

the levels of domestic production and consumer demand;

 

   

the availability of transportation systems with adequate capacity;

 

   

the volatility and uncertainty of regional pricing differentials;

 

   

the price and availability of alternative fuels;

 

   

the effect of energy conservation measures;

 

   

the nature and extent of governmental regulation and taxation;

 

   

fluctuations in demand from electric power generators and industrial customers; and

 

   

the anticipated future prices of oil, natural gas and other commodities.

We May Not Be Able to Increase Our Third-Party Throughput and Resulting Revenue Due to Competition and Other Factors, Which Could Limit Our Ability to Grow, and Extend Our Dependence on QEP.

Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. For the year ended December 31, 2012, QEP accounted for approximately 52% of our total revenues. Our ability to increase our third-party throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. To the extent that we lack available capacity on our systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional oil and natural gas production in our areas of operation.

Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with QEP and (ii) our desire to provide services pursuant to fee-based contracts. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

From Time to Time, We are Involved in Litigation, Claims and Other Proceedings that Could Have a Material Adverse Effect on Our Business, Results of Operations, Financial Condition and Ability to Make Cash Distributions to Our Unitholders.

From time to time, we are involved in litigation, claims and other proceedings relating to the conduct of our business, including but not limited to claims related to the operation of our assets and the services we provide to our customers, as well as claims relating to environmental and regulatory matters. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur material costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Additionally, our insurance coverage may be insufficient to cover adverse judgments against us.

Our gathering systems are the subject of ongoing litigation between Questar Gas Company (QGC) and QEP Field Services Company. QEP Field Services’ former affiliate, QGC, filed its complaint in state court in Utah on May 1, 2012, asserting claims for (1) breach of contract, (2) breach of implied covenant of good faith and fair dealing, (3) an accounting and (4) declaratory judgment related to a 1993 gathering agreement (1993 Agreement) entered when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate Wexpro Company on behalf of QGC’s utility ratepayers. QGC is disputing the annual calculation of the gathering rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment, and is netting this disputed amount from its monthly payment of the gathering fees to QEP

 

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Field Services. As of December 31, 2012, QEP has recorded $3.8 million of deferred revenue related to the QGC disputed amount. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and declaratory judgment relating to its gathering services under the same agreement. It is possible that QGC may amend its complaint to add us as a defendant in the litigation. Please see “Business — Legal Proceedings” for additional information related to the QGC litigation.

Our Exposure to Commodity Price Risk May Vary Over Time.

We currently generate substantially all of our revenues pursuant to fee-based contracts under which we are paid based on the volumes of oil and natural gas that we gather, rather than the underlying value of the oil or natural gas. Consequently, the majority of our existing operations and cash flows have limited direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of oil, natural gas and NGL prices could have a material adverse effect on our business, results of operations and financial condition.

Our Industry Is Highly Competitive, and Increased Competitive Pressure Could Adversely Affect Our Business and Operating Results.

We compete with other similarly sized midstream companies in our areas of operation. Some of our competitors are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors have assets in closer proximity to oil and natural gas supplies and have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our Gathering Contracts Subject Us to Renewal Risks.

We gather the oil and natural gas on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering customers with fee-based contracts may desire to enter into gathering and transportation contracts under different fee arrangements. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially and adversely affected.

Some of Our Gathering Agreements Contain Provisions that can Reduce the Cash Flow Stability that the Agreements were Designed to Achieve.

Several of our gathering agreements related to our Vermillion, Three Rivers and Williston Gathering Systems contain minimum volume commitments that are designed to generate stable cash flows to us from our customers over a specified period of time, while also minimizing direct commodity price risk. Under

 

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these minimum volume commitments, our customers agree to ship a minimum volume of natural gas or oil on our gathering systems over certain periods during the term of the agreement. In addition, certain of our gathering agreements also include an aggregate minimum volume commitment, which is a total amount of natural gas or oil that the customer must transport on our gathering systems over a term specified in the agreement. In these cases, once a customer achieves its aggregate minimum volume commitment, any remaining future minimum volume commitments will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

If a customer’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract year or the term of the minimum volume commitment, as applicable. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer’s actual throughput volumes are above or below its minimum volume commitment for the applicable period, several of our gathering agreements with minimum volume commitments contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments in subsequent periods. These provisions include the following:

 

   

To the extent that a customer’s throughput volumes are less than its minimum volume commitment for the applicable period and the customer makes a deficiency payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer’s applicable minimum volume commitment (depending on the terms of the specific gathering agreement) to the extent that the customer had made a deficiency payment with respect to one or more preceding years.

 

   

To the extent that a customer’s throughput volumes exceed its minimum volume commitment in the applicable period, it is entitled to apply the excess throughput against its aggregate minimum volume commitment, thereby reducing the period for which its annual minimum volume commitment applies. For example, one of our customers has a contracted minimum volume commitment term from December 2007 through December 2017. Should this customer continually ship volumes in excess of its minimum volume commitment, the average remaining period for which our minimum volume commitments apply could be less than the average of the original stated terms of our minimum volume commitment.

 

   

To the extent that a customer’s throughput volumes exceed its minimum volume commitment for the applicable period, there is a crediting mechanism that allows the customer to build a “bank” of credits that it can utilize in the future to reduce deficiency payments owed in subsequent periods, subject to expiration if there is no deficiency payment owed in subsequent periods. The period over which this credit bank can be applied to future deficiency payments varies, depending on the particular gathering agreement.

Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could result in our receiving reduced revenues or cash flows from one or more customers in a given period, and thus could reduce our cash available for distribution.

We Depend on a Relatively Limited Number of Customers for a Significant Portion of Our Revenues. The Loss of, or Material Nonpayment or Nonperformance By, Any One or More of These Customers Could Adversely Affect Our Ability to Make Cash Distributions to You.

A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for over 90% of our revenue for the year ended December 31, 2012. We have gathering contracts with each of these customers of varying duration and commercial terms. If we were

 

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unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. QEP and Questar accounted for approximately 52% and 16%, respectively, of our revenue for the year ended December 31, 2012. In addition, some of our customers may have material financial or liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenues and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively limited number of customers for a substantial portion of our revenue.

If Third-Party Pipelines or Other Midstream Facilities Interconnected to Our Gathering or Transportation Systems Become Partially or Fully Unavailable, or If the Volumes We Gather or Transport Do Not Meet the Natural Gas Quality Requirements of Such Pipelines or Facilities, Our Gross Operating Margin and Cash Flow and Our Ability to Make Distributions to Our Unitholders Could Be Adversely Affected.

Our gathering and transportation pipelines connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as the Kern River Pipeline, the Northwest Pipeline, the Rockies Express Pipeline and others. The continuing operation of such third-party pipelines, processing plants and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our gross margin and ability to make cash distributions to our unitholders could be adversely affected.

Our Business Involves Many Hazards and Operational Risks, Some of Which May Not Be Fully Covered By Insurance. If a Significant Accident or Event Occurs for Which We Are Not Adequately Insured, or If We Fail to Recover All Anticipated Insurance Proceeds for Significant Accidents or Events for Which We Are Insured, Our Operations and Financial Results Could Be Adversely Affected.

Our operations are subject to all of the risks and hazards inherent in the gathering of oil and natural gas, including:

 

   

damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters, acts of terrorism and actions by third parties;

 

   

damage from construction, vehicles, farm and utility equipment or other causes;

 

   

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

 

   

ruptures, fires and explosions; and

 

   

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These and similar risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could also have a material adverse effect on our operations. We are not fully

 

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insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

Terrorist or Cyber-attacks and Threats, Escalation of Military Activity in Response to these Attacks or Acts of War Could Have a Material Adverse Effect on Our Business, Financial Condition or Results of Operations.

Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

We Intend to Grow Our Business in Part By Seeking Strategic Acquisition Opportunities. If We Are Unable to Make Acquisitions on Economically Acceptable Terms from QEP or Third Parties, Our Future Growth Will Be Affected. In Addition, the Acquisitions We Do Make May Reduce, Rather Than Increase, Our Cash Generated from Operations on a Per Unit Basis.

Our ability to grow is affected, in part, by our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including QEP. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

If we are unable to make accretive acquisitions from QEP or third parties, whether because we are (i) unable to identify attractive acquisition prospects or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

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

 

   

mistaken assumptions about volumes, revenue, costs and synergies;

 

   

an inability to secure adequate customer commitments to use the acquired systems or facilities;

 

   

that oil or natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

 

 

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an inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with the newly acquired assets;

 

   

coordinating geographically disparate organizations, systems and facilities;

 

   

the assumption of unknown liabilities;

 

   

limitations on the right to indemnity from the seller;

 

   

mistaken assumptions about the overall costs of equity or debt;

 

   

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

 

   

unforeseen difficulties operating in new geographic areas and business lines; and

 

   

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our Growth Strategy Requires Access to New Capital. Tightened Capital Markets or Increased Competition for Investment Opportunities Could Impair Our Ability to Grow.

We continuously consider and enter into discussions regarding potential acquisitions or growth capital expenditures. Any limitations on our access to new capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, including our then current unit price, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair our ability to execute our growth strategy.

In addition, we are experiencing increased competition for the types of assets we contemplate purchasing. Weak economic conditions and competition for asset purchases could limit our ability to fully execute our growth strategy.

The Credit and Risk Profile of Our General Partner and Its Owner, QEP, Could Adversely Affect Our Credit Ratings and Risk Profile, Which Could Increase Our Borrowing Costs or Hinder Our Ability to Raise Capital.

The credit and business risk profiles of our general partner and QEP may be factors considered in credit evaluations of us. This is because our general partner, which is owned by QEP, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of QEP, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of QEP’s grade credit rating, may adversely affect our credit ratings and risk profile. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or QEP, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of QEP and its

 

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affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.

Because Our Common Units Will Be Yield-Oriented Securities, Increases in Interest Rates Could Adversely Impact Our Unit Price, Our Ability to Issue Equity or Incur Debt for Acquisitions or Other Purposes and Our Ability to Make Cash Distributions at Our Intended Levels.

Interest rates may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Debt We Incur in the Future May Limit Our Flexibility to Obtain Financing and to Pursue Other Business Opportunities.

Upon the closing of this offering, we expect to have no debt and $         million available for future borrowings under our new credit facility. Our future level of debt could have important consequences for us, including the following:

 

   

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

 

   

our funds available for operations, future business opportunities and cash distributions to unitholders may be reduced by that portion of our cash flow required to make interest payments on our debt;

 

   

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

   

our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our 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 control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to take any of these actions on satisfactory terms or at all.

A Shortage of Skilled Labor in the Midstream Industry Could Reduce Labor Productivity and Increase Costs, Which Could Have a Material Adverse Effect on Our Business and Results of Operations.

The gathering of oil and natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor costs and overall productivity could be materially and adversely affected. If our labor costs increase or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.

 

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Restrictions in Our New Credit Facility Could Adversely Affect Our Business, Financial Condition, Results of Operations, Ability to Make Distributions to Unitholders and Value of Our Common Units.

We intend to enter into a new credit facility in connection with the closing of this offering. Our new credit facility is likely to limit our ability to, among other things:

 

   

incur or guarantee additional debt;

 

   

make distributions on or redeem or repurchase units;

 

   

make certain investments and acquisitions;

 

   

make capital expenditures;

 

   

incur certain liens or permit them to exist;

 

   

enter into certain types of transactions with affiliates;

 

   

merge or consolidate with another company; and

 

   

transfer, sell or otherwise dispose of assets.

Our new credit facility also will likely include covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

We Do Not Own All of the Land on Which Our Pipelines Are Located, Which Could Result in Disruptions to Our Operations.

We do not own all of the land on which our pipelines are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Certain of Our Gathering Systems, Including Our Operations in the Bakken Shale, Are Located On Native American Tribal Lands and Are Subject to Various Federal and Tribal Approvals and Regulations, Which May Increase Our Costs and Delay or Prevent Our Efforts to Conduct Planned Operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management (BLM) and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that

 

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apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue our operations on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas and oil gathering operations on such lands.

Increased Regulation of Hydraulic Fracturing Could Result in Reductions or Delays in Oil and Natural Gas Production By Our Customers, Which Could Adversely Impact Our Revenues.

A portion of our customers’ oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, from time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. The EPA released a progress report on its study on December 21, 2012, and stated that a draft report of the findings of the study is expected in late 2014 for peer review and comment. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend for hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. Certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, effective April 1, 2012, the Colorado Oil and Gas Conservation Commission implemented rules requiring public disclosure of hydraulic fracturing fluid contents for wells drilled, requiring public disclosure of hydraulic fracturing fluid contents for wells drilled under drilling permits within 60 days of well simulation. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We cannot predict whether any other legislation will be enacted and if so, what its provisions will be. If additional levels of regulation and permits are required through the adoption of new

 

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laws and regulations at the federal, state or local level, that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines, which could reduce the volumes of natural gas available to move through our gathering systems, which could materially adversely affect our revenue and results of operations.

Further, on August 16, 2012, the EPA published final rules that subject oil and natural gas operations (including production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically-fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must be the REC techniques, with or with combustion devices, after January 1, 2015. However, the EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules in 2013 that are likely responsive to some of these requests. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

The U.S. Department of the Interior has also announced its intention to propose a new rule regulation hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to increased operating costs in the production of oil and natural gas, or could make it more difficult to perform hydraulic fracturing, either of which could have an adverse effect on our operations. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Our Construction of New Assets May Not Result in Revenue Increases and Will Be Subject to Regulatory, Environmental, Political, Legal and Economic Risks, Which Could Adversely Affect Our Results of Operations and Financial Condition.

One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not occur or only occurs over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that

 

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area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

Moreover, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way or environmental authorizations. We may be unable to obtain such rights-of-way or authorizations and may, therefore, be unable to connect new natural gas volumes to our systems or to capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or authorizations or to renew existing rights-of-way or authorizations. If the cost of renewing or obtaining new rights-of-way or authorizations increases materially, our cash flows could be adversely affected.

The Majority of Our Pipelines Are Not Subject to Regulation By the Federal Energy Regulatory Commission; However, a Change in the Jurisdictional Characterization of Our Assets, or a Change in Policy, Could Result in Increased Regulation of Our Assets Which Could Materially and Adversely Affect Our Financial Condition, Results of Operations and Cash Flows.

The substantial majority of our pipeline assets are gas-gathering facilities or interests in gas-gathering facilities. Natural gas gathering facilities are exempt from the jurisdiction of the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938 (NGA). Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by the FERC on a case-by-case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

Our Gathering Systems Are Subject to State Regulation That Could Materially and Adversely Affect Our Operations and Cash Flows.

State regulation of gathering facilities includes safety and environmental requirements. Several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations, may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our operations and revenues.

Two of Our Pipelines Are Regulated by the FERC, Which May Adversely Affect Our Revenues and Results of Operations.

We own an interstate gas pipeline company, Rendezvous Pipeline, which is regulated by the FERC under the NGA. The FERC has approved market-based rates for Rendezvous Pipeline allowing it to charge

 

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rates that customers will accept. The FERC has also established rules, policies and practices across the range of its natural gas regulatory activities, including, for example, policies on open access transportation, construction of new facilities, market transparency, market manipulation, ratemaking, capacity release, segmentation and market center promotion, which both directly and indirectly affect our business, and could materially and adversely affect our operations and revenues.

We also own a common carrier crude oil pipeline that is regulated by the FERC under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992, or EPAct 1992, and the rules and regulations promulgated under those laws. FERC regulates the rates and terms and conditions of service, including access rights, for interstate shipments on our common carrier crude oil pipeline. As result of FERC regulation, we may not be able to choose our customers or recover some of our costs of service allocable to such interstate transportation service, which may adversely affect our revenues and result of operations.

We Are Subject to Stringent Environmental Laws and Regulations That May Expose Us to Significant Costs and Liabilities.

Our oil and natural gas gathering operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:

 

   

the federal Clean Air Act and analogous state laws that restrict emissions of air pollutants from any sources and impose obligations related to pre-construction activities and monitoring and reporting air emissions;

 

   

the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

 

   

the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

 

   

the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;

 

   

the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;

 

   

the federal Endangered Species Act, also known as the ESA, that restricts activities that may affect endangered and threatened species or their habitats; and

 

   

the federal Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of

 

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our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us 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. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read “Business — Environmental Matters” for more information.

We May Incur Greater Than Anticipated Costs and Liabilities as a Result of Safety Regulation, Including Pipeline Integrity Management Program Testing and Related Repairs.

Pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Hazardous Liquid Pipeline Safety Act of 1979, or the HLPSA, as amended by the Pipeline Safety Act of 1992, or the PSA, the Accountable Pipeline Safety and Partnership Act of 1996, or the APSA, the Pipeline Safety Improvement Act of 2002, or the PSIA, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act, and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, the Department of Transportation, or the DOT, through the Pipeline and Hazardous Materials Safety Administration (PHMSA), has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm. The regulations require the operators of covered pipelines to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur less than $25,000 in costs during 2013 to complete the testing required by existing DOT regulations and their state counterparts. This estimate does not include the costs for any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from shutting down our pipelines during the pendency of such repairs.

The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to

 

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expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. On August 13, 2012, PHMSA published a proposed rulemaking consistent with the signed act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. Should we fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines. PHMSA published a final rule in May 2011 expanding pipeline safety requirements including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner. PHMSA has also published advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management requirements to additional types of facilities pipelines, such as gathering pipelines and related facilities. In addition, PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure, which could result in additional pressure testing of pipelines or the reduction of maximum operating pressures. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue added capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations and cash flow.

Climate Change Legislation, Regulatory Initiatives and Litigation Could Result in Increased Operating Costs and Reduced Demand for the Oil and Natural Gas Services We Provide.

In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, in December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, in September 2009, the EPA issued a final rule requiring the monitoring and reporting of GHG emissions from specified large greenhouse gas emission sources in the United States and, in November 2010, expanded this existing GHG emissions reporting rule

 

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for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year, requiring reporting of GHG emissions by regulated petroleum and natural gas facilities to the EPA beginning in 2012 and annually thereafter. Currently, it is anticipated that several of our facilities will likely be required to report under this rule. However, operational or regulatory changes could require some or all of our other facilities to be required to report GHG emissions at a future date. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. Several of the EPA’s GHG rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHGs could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The Adoption and Implementation of New Statutory and Regulatory Requirements for Swap Transactions Could Have an Adverse Impact on Our Ability to Hedge Risks Associated With Our Business and Increase the Working Capital Requirements to Conduct These Activities.

In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act requires the Commodities Futures Trading Commission and the Securities and Exchange Commission to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps entities, the clearing of certain swaps, the reporting and recordkeeping of swaps, and expanded enforcement such as establishing position limits. Although the Commodities Futures Trading Commission established position limits on certain core futures and equivalent swaps contracts, including natural gas, with exceptions for certain bona fide hedging transactions, those limits were vacated by the federal district court on September 28, 2012, and will not go into effect unless the Commodities Futures Trading Commission prevails on appeal of this ruling, or issues and finalizes revised rules.

In December 2012, the Commodities Futures Trading Commission published final rules regarding mandatory clearing of four classes of interest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for end users of swaps, September 9, 2013. The impact of the Dodd-Frank Act on our future hedging activities is uncertain at this time. However, the new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.

 

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Our Ability to Operate Our Business Effectively Could Be Impaired If We Fail to Attract and Retain Key Management Personnel.

Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience. Competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

If We Fail to Develop or Maintain an Effective System of Internal Controls, We May Not Be Able to Report Our Financial Results Timely and Accurately or Prevent Fraud, Which Would Likely Have a Negative Impact on the Market Price of Our Common Units.

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Exchange Act. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.

Although we will be required to disclose changes made in our internal control and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until our annual report for the fiscal year ending December 31, 2014.

Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a material adverse effect on the trading price of our common units.

For as Long as We are an Emerging Growth Company, We Will Not Be Required to Comply with Certain Disclosure Requirements That Apply to Other Public Companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our limited partner interests held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

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In addition, the JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common units to be less attractive as a result, there may be a less active trading market for our common units and our trading price may be more volatile.

Risks Inherent in an Investment in Us

Our General Partner and Its Affiliates, Including QEP, Have Conflicts of Interest with Us and Limited Duties to Us and Our Unitholders, and They May Favor Their Own Interests to Our Detriment and That of Our Unitholders. Additionally, We Have No Control Over QEP’s Business Decisions and Operations, and QEP is Under No Obligation to Adopt a Business Strategy That Favors Us.

Following the offering, QEP will own a 2.0% general partner interest and a     % limited partner interest in us and will own and control our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, QEP. Conflicts of interest may arise between QEP and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including QEP, over the interests of our common unitholders. These conflicts include, among others, the following situations:

 

   

neither our partnership agreement nor any other agreement requires QEP to pursue a business strategy that favors us, and the directors and officers of QEP have a fiduciary duty to make these decisions in the best interests of the stockholders of QEP. QEP may choose to shift the focus of its investment and growth to areas not served by our assets;

 

   

QEP may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

 

   

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

   

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

   

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

 

   

our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;

 

   

our general partner will determine which costs incurred by it are reimbursable by us;

 

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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, to make incentive distributions or to accelerate expiration of the subordination period;

 

   

our partnership agreement permits us to classify up to $         million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

 

   

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;

 

   

our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of the common units;

 

   

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

 

   

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

 

   

our general partner may elect to cause us to issue common 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 the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” and “Conflicts of Interest and Duties.”

Our Partnership Agreement Requires That We Distribute All of Our Available Cash, Which Could Limit Our Ability to Grow and Make Acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of 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. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking

 

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senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.

While Our Partnership Agreement Requires Us to Distribute All of Our Available Cash, Our Partnership Agreement, Including the Provisions Requiring Us to Make Cash Distributions, May Be Amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by QEP) after the subordination period has ended. Upon the expiration of 30 days following this offering and assuming no exercise of the underwriters option to purchase additional common units, QEP will own, directly or indirectly, approximately     % of the outstanding common units and all of our outstanding subordinated units. Please read “The Partnership Agreement — Amendment of Our Partnership Agreement.”

Our Partnership Agreement Replaces Our General Partner’s Fiduciary Duties to Holders of Our Common Units With Contractual Standards Governing Its Duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the language in our partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties — Duties of the General Partner.”

Our Partnership Agreement Restricts the Remedies Available to Holders of Our Common and Subordinated Units for Actions Taken By Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

 

   

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

   

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;

 

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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, 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 our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

Our General Partner Intends to Limit Its Liability Regarding Our Obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

If You Are Not Both a Citizenship Eligible Holder and a Rate Eligible Holder, Your Common Units May Be Subject to Redemption.

In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body, and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. Please read “Description of the Common Units — Transfer of Common Units.” If you are not a person who meets the requirements to be a citizenship eligible holder and a rate eligible holder, you run the risk of having your units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if you are not a person who meets the requirements to be a citizenship eligible holder, you will not be entitled to voting rights. Please read “Our Partnership Agreement — Redemption of Ineligible Holders.”

 

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Cost Reimbursements, Which Will Be Determined in Our General Partner’s Sole Discretion, and Fees Due Our General Partner and Its Affiliates for Services Provided Will Be Substantial and Will Reduce Our Cash Available for Distribution to You.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement, our general partner determines the amount of these expenses. Under the terms of the omnibus agreement we will be required to reimburse QEP for the provision of certain general and administrative services to us. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders.

Unitholders Have Very Limited Voting Rights and, Even If They Are Dissatisfied, They Cannot Remove Our General Partner Without Its Consent.

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 did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are wholly owned subsidiaries of QEP. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At closing, our general partner and its affiliates will own     % of the common units and subordinated units. Also, if our general partner is removed without cause during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the 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 the 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 unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% 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.

 

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Our General Partner Interest or the 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, there is no restriction in our partnership agreement on the ability of QEP to transfer its membership interest in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

The Incentive Distribution Rights of Our General Partner May Be Transferred to a Third Party Without Unitholder Consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of QEP selling or contributing additional midstream assets to us, as QEP would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

You Will Experience Immediate and Substantial Dilution in Pro Forma Net Tangible Book Value of $         Per Common Unit.

The assumed initial public offering price of $         per common unit exceeds our pro forma net tangible book value of $         per unit. Based on an assumed initial public offering price of $         per common unit, you will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed by QEP are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

We May Issue Additional Units Without Unitholder Approval, Which Would Dilute Unitholder Interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our revolving credit facility prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. 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;

 

   

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 our common units may decline.

 

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QEP May Sell Units in the Public or Private Markets, and Such Sales Could Have an Adverse Impact on the Trading Price of the Common Units.

After the sale of the common units offered by this prospectus, QEP will hold                  common units and                  subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide QEP with certain registration rights. Please read “Units Eligible for Future Sale.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our General Partner’s Discretion in Establishing Cash Reserves May Reduce the Amount of Cash Available for Distribution to Unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Affiliates of Our General Partner, Including QEP, May Compete with Us, and Neither Our General Partner Nor Its Affiliates Have Any Obligation to Present Business Opportunities to Us.

Neither our partnership agreement nor our omnibus agreement will prohibit QEP or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, QEP and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from QEP and other affiliates of our general partner could materially adversely impact our results of operations and cash available for distribution to unitholders.

Our General Partner May Cause Us to Borrow Funds in Order to Make Cash Distributions, Even Where the Purpose or Effect of the Borrowing Benefits the General Partner or Its Affiliates.

In some instances, our general partner may cause us to borrow funds under our revolving credit facility, from QEP or otherwise from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.

Our General Partner Has a Limited Call Right That May Require You to Sell Your Common Units at an Undesirable Time or Price.

If at any time our general partner and its affiliates own more than 80.0% of our 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. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately     % of our common units. At the end of the subordination period (which could occur as early as                     , 2014), assuming no additional issuances of common units (other than upon the conversion of the subordinated units) and no exercise of the underwriters’ option to purchase additional common units,

 

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our general partner and its affiliates will own approximately     % of our common units . For additional information about the call right, please read “Our 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 non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. 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 jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine 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 the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Please read “Our Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Unitholders May Have to Repay Distributions That Were Wrongfully Distributed to Them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership 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. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our 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.

There is No Existing Market for Our Common Units, and a Trading Market That Will Provide You With Adequate Liquidity May Not Develop. The Price of Our Common Units May Fluctuate Significantly, and You Could Lose All or Part of Your Investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only publicly traded common units. In addition, QEP will own                  common units and                  subordinated units, representing an aggregate     % limited partner interest in us. 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.

 

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The initial public offering price for the common units offered hereby 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 influenced 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;

 

   

announcements by us or our 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.”

Our General Partner, or Any Transferee Holding Incentive Distribution Rights, May Elect to Cause Us to Issue Common Units and General Partner Units to It in Connection with a Resetting of the Target Distribution Levels Related to Its Incentive Distribution Rights, Without the Approval of Our Conflicts Committee or the Holders of Our Common Units. This Could Result in Lower Distributions to Holders of Our Common Units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal 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.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain our general partner’s interest in us at the level that existed immediately prior to the reset election. 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. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for

 

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resetting target distributions have been fulfilled. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

The NYSE Does Not Require a Publicly Traded Limited Partnership Like Us to Comply with Certain of Its Corporate Governance Requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to shareholders of corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management — Management of QEP Midstream Partners, LP.”

We Will Incur Increased Costs as a Result of Being a Publicly Traded Partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. For example, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs, including requirements to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting.

In addition, following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make certain activities more time-consuming and costly.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our general partner’s board or as executive officers.

We estimate that we will incur approximately $2.5 million of estimated incremental external costs per year and additional internal costs associated with being a publicly traded partnership. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be reduced by the costs associated with being a public company.

Tax Risks

In addition to reading the following risk factors, please read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our Tax Treatment Depends on Our Status as a Partnership for Federal Income Tax Purposes. If the Internal Revenue Services (IRS) Were to Treat Us as a Corporation for Federal Income Tax Purposes, Which Would Subject Us to Entity-Level Taxation, Then Our Cash Available for Distribution to Our Unitholders Would Be Substantially Reduced.

The anticipated after-tax economic benefit of an investment in our 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.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes.

 

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A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

If We Were Subjected to a Material Amount of Additional Entity-Level Taxation By Individual States, It Would Reduce Our Cash Available for Distribution to Our Unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially 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 entity-level taxation, the minimum quarterly distribution amount and the target distribution levels may 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, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “Material Federal Income Tax Consequences — Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

Our Unitholders’ Share of Our Income Will Be Taxable to Them for Federal Income Tax Purposes Even If They Do Not Receive Any Cash Distributions from Us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

 

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If the IRS Contests the Federal Income Tax Positions We Take, the Market for Our Common Units May Be Adversely Impacted 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. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. 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 and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on 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.

Tax Gain or Loss on the Disposition of Our Common Units Could Be More or Less Than Expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units, may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt Entities and Non-U.S. Persons Face Unique Tax Issues from Owning Our Common Units That May Result in Adverse Tax Consequences to Them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), 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 federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We Will Treat Each Purchaser of 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 the Common Units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Latham & Watkins LLP is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your 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. Please read “Material Federal Income Tax Consequences — Tax

 

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Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We Prorate Our Items of Income, Gain, Loss and Deduction for Federal Income Tax Purposes 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 will prorate our items of income, gain, loss and deduction for federal income tax purposes 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. Recently, however, the U.S. Treasury Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. 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. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

A Unitholder Whose Common Units Are Loaned to a “Short Seller” to Effect a Short Sale of Common Units May Be Considered as Having Disposed of Those Common Units. If So, He Would No Longer Be Treated for Federal Income Tax Purposes as a Partner With Respect to Those Common Units During the Period of the Loan and May Recognize Gain or Loss from the Disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We Will Adopt Certain Valuation Methodologies and Monthly Conventions for Federal Income Tax Purposes That May 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 the 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 our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal

 

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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 taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

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 taxable 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.

The Sale or Exchange of 50.0% or More of Our Capital and Profits Interests During Any Twelve-Month Period Will Result in the Termination of Our Partnership for Federal Income Tax Purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a Result of Investing in Our Common Units, You May Become Subject to State and Local Taxes and Return Filing Requirements in Jurisdictions Where We Operate or Own or Acquire Properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely 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, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Colorado, North Dakota, Utah and Wyoming. Some of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Latham & Watkins LLP has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.

 

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of                  common units offered by this prospectus, based on an assumed initial public offering price of $         per common unit, after deducting underwriting discounts, estimated offering expenses and structuring fees. We intend to use these proceeds as follows:

 

   

make a cash distribution to QEP of $         million, a portion of which will be used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to us;

 

   

distribute $         million to QEP Operating, which will use those funds to repay all $         million of its outstanding debt; and

 

   

pay revolving credit facility origination fees of $         million.

As of December 31, 2012, we had approximately $146.8 million of debt outstanding, comprised of intercompany loans from QEP that bear interest at 6.05% and are due March 31, 2013 and 2017. Our outstanding indebtedness was incurred to primarily fund capital expenditures.

The net proceeds from any exercise by the underwriters of their option to purchase additional common units will be used to redeem from QEP a number of common units equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Accordingly, any exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease by $         million, based on an assumed initial public offering price of $         per common unit. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $         per common unit, would increase net proceeds to us from this offering by approximately $         million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $         per common unit, would decrease the net proceeds to us from this offering by approximately $         million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the cash distribution to QEP from the proceeds of this offering will increase or decrease, as applicable, by a corresponding amount.

The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Please read “Underwriting.”

 

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CAPITALIZATION

The following table shows:

 

   

the historical cash and cash equivalents and capitalization of our Predecessor as of December 31, 2012;

 

   

our pro forma capitalization as of December 31, 2012, giving effect to the pro forma adjustments described in our unaudited pro forma combined financial data included elsewhere in this prospectus; and

 

   

our pro forma as adjusted capitalization as of December 31, 2012, giving effect to this offering and the application of the net proceeds from this offering in the manner described under “Use of Proceeds” and the other transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure.”

This table is derived from, should be read together with and is qualified in its entirety by reference to the historical interim combined financial statements and the accompanying notes and the pro forma combined financial data and accompanying notes included elsewhere in this prospectus.

 

     As of December 31, 2012  
     Historical      Pro Forma      Pro Forma
As  Adjusted
 
     (in millions)  

Cash and cash equivalents

   $ 1.4       $ 1.4       $            
  

 

 

    

 

 

    

 

 

 

Debt:

        

Long-term debt

   $ 134.2       $ —         $     

Revolving credit facility

     —           —        
  

 

 

    

 

 

    

 

 

 

Total long-term debt (including current maturities)

     134.2         —        
  

 

 

    

 

 

    

 

 

 

Net investment/equity:

        

Net investment

     500.7         494.0      

Common Units — public

     —           —        

Common Units — QEP

     —           —        

Subordinated Units — QEP

     —           —        

Noncontrolling interest

     47.7         47.7      

General partner equity

     —           —        
  

 

 

    

 

 

    

 

 

 

Total equity

   $ 548.4       $ 541.7       $     
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 682.6       $ 541.7       $     
  

 

 

    

 

 

    

 

 

 

 

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of                 , 2013, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $         million, or $         per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma 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(1)

      $            

Pro forma net tangible book value per unit before the offering(2)

   $               

Decrease in net tangible book value per unit attributable to purchasers in the offering

     
  

 

 

    

 

 

 

Less: Pro forma net tangible book value per unit after the offering(3)

     

Immediate dilution in net tangible book value per common unit to purchasers in the offering(4)(5)

      $            
  

 

 

    

 

 

 

 

(1) The mid-point of the price range set forth on the cover of this prospectus.

 

(2) Determined by dividing the number of units (                      common units,                      subordinated units and                      general partner units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities.

 

(3) Determined by dividing the number of units to be outstanding after this offering (                      total common units,                      subordinated units and                      general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.

 

(4) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $         and $        , respectively.

 

(5) Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

 

     Units Acquired     Total
Consideration
 
     Number    %     Amount      %  
     (in millions)          (in millions)         

General partner and its affiliates(1)(2)(3)

                   $                    

Purchasers in this offering

                   $                    
  

 

  

 

 

   

 

 

    

 

 

 

Total

                   $                  100.0
  

 

  

 

 

   

 

 

    

 

 

 

 

(1) Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own                     common units,                      subordinated units and                      general partner units.

 

(2) Assumes the underwriters’ option to purchase additional common units is not exercised.

 

(3) The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with accounting principles generally accepted in the United States. Book value of the consideration provided by the general partner and its affiliates, as of                     , 2013, after giving effect to the application of the net proceeds of the offering, is as follows:

 

     (in millions)  

Book value of net assets contributed

   $            

Less: Distribution to QEP from net proceeds of this offering

  
  

 

 

 

Total consideration

   $            
  

 

 

 

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, “Forward-Looking Statements” and “Risk Factors” should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, please refer to our audited historical combined financial statements and accompanying notes and the unaudited pro forma combined financial data and accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement. To that end, our partnership agreement requires us to distribute all of our available cash quarterly. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

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

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

 

   

Our cash distribution policy will be subject to restrictions on cash distributions under our revolving credit facility. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our revolving credit facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility.”

 

   

The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

   

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “Our Partnership Agreement — Amendment of Our Partnership Agreement — No Unitholder Approval.” However, after the subordination period has ended our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, QEP will own our general partner

 

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and will indirectly own an aggregate of approximately     % of our outstanding common units and subordinated units . Please read “Our Partnership Agreement — Amendment of Our Partnership Agreement.”

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution 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 cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash.”

 

   

Our ability to make cash distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

 

   

If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. Any shortfall in the payment of the minimum quarterly distribution with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

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

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. Our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors — Risks Related to Our Business — Restrictions in Our New Credit Facility Could Adversely Affect Our Business, Financial Condition, Results of Operations, Ability to Make Cash Distributions to Unitholders and Value of Our Common Units.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have

 

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increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors — Risks Related to Our Business — Debt We Incur in the Future May Limit Our Flexibility to Obtain Financing and to Pursue Other Business Opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “— General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately preceding the indicated distribution date. We do not expect to make distributions for the period that begins on                     , 2013 and ends on the day prior to the closing of this offering other than the distribution to be made to QEP in connection with the closing of this offering as described in “Prospectus Summary — Formation Transactions and Partnership Structure” and “Use of Proceeds.” We will adjust the amount of our first distribution for the period from the closing of this offering through                     , 2013 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and on an annualized basis is summarized in the table below:

 

          Minimum Quarterly
Distributions
 
          (in millions)  
     Number of Units    One Quarter      Annualized
(Four
Quarters)
 

Publicly held common units

      $                $            

Common units held by QEP(1)

        

Subordinated units held by QEP

        

General partner units

        
  

 

  

 

 

    

 

 

 

Total

      $         $     
  

 

  

 

 

    

 

 

 

 

(1) Assumes no exercise of the underwriters’ option to purchase additional common units.

As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner’s initial 2.0% 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 in order to maintain its initial 2.0% general partner interest. Our general partner will also hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $         per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, 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

 

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subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is not adverse to the best interests of our partnership. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution will also automatically be adjusted in connection with the resetting of the target distribution levels related to our general partner’s incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $         per unit for the twelve months ending June 30, 2014. In those sections, we present two tables, consisting of:

 

   

“Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended December 31, 2012, derived from our unaudited pro forma financial data that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

 

   

“Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2014,” in which we provide our estimated forecast of our ability to generate sufficient cash available for distribution for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2014.

 

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Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012

If we had completed the transactions contemplated in this prospectus on January 1, 2012, our unaudited pro forma cash available for distribution would have been approximately $71.6 million for the year ended December 31, 2012. This amount would have been sufficient to pay the minimum quarterly distribution of $         per unit per quarter ($         per unit on an annualized basis) on all of our common units and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for such period.

Our unaudited pro forma available cash for the year ended December 31, 2012 includes $2.5 million of estimated incremental annual general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental annual general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental annual general and administrative expenses related to being a publicly traded partnership include expenses associated with annual, quarterly and current reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees, outside director fees and director and officer insurance expenses. These expenses are not reflected in our or our Predecessor’s historical financial statements.

Our estimate of incremental annual general and administrative expenses is based upon currently available information. The adjusted amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus been completed as of the date indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma 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 completed the transactions contemplated in this prospectus on the dates indicated.

 

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The following table illustrates, on a pro forma basis, for the year ended December 31, 2012, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering had been completed at the beginning of such period. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

QEP Midstream Partners, LP Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2012
 
     (in millions, except
per unit data)
 

Pro Forma Net Income Attributable to Us

   $ 55.8   

Add:

  

Depreciation and amortization, net of noncontrolling interest(1)

     27.8   

Interest expense, net

     2.4   
  

 

 

 

Pro Forma Adjusted EBITDA(2)

   $ 86.0   
  

 

 

 

Less:

  

Incremental general and administrative expenses associated with being a publicly traded partnership(3)

     2.5   

Cash interest expense, net of interest income

     1.5   

Expansion capital expenditures(4)

     19.2   

Maintenance capital expenditures(5)

     10.4   

Add:

  

Available cash and borrowings to fund expansion capital expenditures

     19.2   
  

 

 

 

Pro Forma Available Cash

   $ 71.6   
  

 

 

 

Implied Cash Distribution at the Minimum Quarterly Distribution Rate:

  

Annualized minimum quarterly distribution per unit

   $     

Distributions to public common unitholders

  

Distributions to QEP — common units

  

Distributions to QEP — subordinated units

  

Distributions to general partner

  

Total distributions to unitholders and general partner

   $     
  

 

 

 

Excess (shortfall)

   $     
  

 

 

 

Percent of minimum quarterly distribution payable to common unitholders

  
  

 

 

 

Percent of minimum quarterly distribution payable to subordinated unitholders

  
  

 

 

 

 

(1) Our total pro forma depreciation expense of $30.6 million includes $2.8 million of depreciation expense allocable to Western Gas’ investment in Rendezvous Gas.

 

(2) For a definition of Adjusted EBITDA and a reconciliation to net income attributable to us and cash flows from operating activities, the most directly comparable financial measures calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Business.”

 

(3) Represents estimated cash expense associated with being a publicly traded partnership, such as expenses associated with annual, quarterly and current reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees, outside director fees and director and officer insurance expenses.

 

(4)

For the year ended December 31, 2012, our total capital expenditures were $29.6 million. Historically, we did not make a distinction between maintenance and expansion capital expenditures; however, for purposes of the presentation of our Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $19.2 million of these capital

 

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  expenditures were expansion capital expenditures for the year ended December 31, 2012. Expansion capital expenditures are those cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Capital Expenditures.”

 

(5) For the year ended December 31, 2012, our total capital expenditures were $29.6 million. Historically, we did not make a distinction between maintenance and expansion capital expenditures, however for purposes of the presentation of our Unaudited Pro Forma Cash Available for Distribution, we have estimated that approximately $10.4 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2012. Maintenance capital expenditures are those cash expenditures incurred to maintain operating capacity or operating income over the long-term. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Capital Expenditures.”

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2014

We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2014 will be approximately $70.1 million. This amount would exceed by $         million the amount needed to pay the total annualized minimum quarterly distribution of $         on all of our common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for the twelve months ending June 30, 2014.

We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated cash available for distribution and related assumptions and considerations set forth below to substantiate our belief that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for the twelve months ending June 30, 2014. This forecast is a forward-looking statement and should be read together with the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for the twelve months ending June 30, 2014. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to the Partnership’s and the Predecessor’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum estimated cash available for distribution necessary to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for the twelve months ending June 30, 2014.

 

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We are providing the forecast of estimated cash available for distribution and related assumptions set forth below to supplement the historical and pro forma combined financial statements in support of our expectation that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest, for the twelve months ending June 30, 2014. Please read below under “— Assumptions and Considerations” 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 financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the total annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our general partner’s 2.0% interest for the twelve months ending June 30, 2014, should not be regarded as a representation by us, the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

 

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QEP Midstream Partners, LP Estimated Cash Available For Distribution

 

     Twelve Months
Ending

June  30, 2014
 
     (in millions,
except per unit
data)
 

Revenues

  

Gathering and transportation

   $ 118.8   

Condensate sales

     7.5   
  

 

 

 

Total revenues

   $ 126.3   
  

 

 

 

Operating expenses

  

Gathering expense

   $ 22.8   

General and administrative(1)

     15.6   

Taxes other than income taxes

     1.9   

Depreciation and amortization

     32.0   
  

 

 

 

Total operating expenses

     72.3   
  

 

 

 
Operating income      54.0   
  

 

 

 

Other income

     0.1   

Income from unconsolidated affiliate(2)

     2.8   

Interest expense(3)

     (2.6

Net income

   $ 54.3   
  

 

 

 

Net income attributable to noncontrolling interest

     (3.3
  

 

 

 

Net income attributable to us

   $ 51.0   
  

 

 

 

Plus:

  

Depreciation and amortization expense, net of noncontrolling interest portion(4)

     29.2   

Interest expense

     2.6   

Less:

  

Interest income

     0.1   
  

 

 

 

Adjusted EBITDA(5)

   $ 82.7   
  

 

 

 

Less:

  

Cash interest expense, net of interest income(6)

     1.6   

Expansion capital expenditures(7)

       

Maintenance capital expenditures(8)

     11.0   

Add:

  

Available cash and borrowings to fund expansion capital expenditure

       
  

 

 

 

Estimated cash available for distribution

   $ 70.1   
  

 

 

 

Implied cash distribution at the minimum quarterly distribution rate:

  

Annualized minimum quarterly distribution per unit

   $     

Distributions to public common unit holders

  

Distributions to QEP — common units

  

Distributions to QEP — subordinated units

  

Distributions to general partner

  
  

 

 

 

Total distribution to our unitholders and general partner

   $     
  

 

 

 

Excess of cash available for distribution over aggregate annualized minimum quarterly distributions

   $     

 

(1) Includes $2.5 million of estimated incremental annual cash expenses associated with being a publicly traded partnership. For more information regarding the general and administrative expense allocation, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Business — Operating Expenses — General and Administrative Expenses.”

 

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(2) Represents the earnings from our 50% ownership interest in Three Rivers Gathering.

 

(3) Includes interest expense on funds used for expansion capital expenditures and costs incurred in connection with our new revolving credit facility.

 

(4) Depreciation and amortization expense of $29.2 million excludes $2.8 million of depreciation expense allocable to Western Gas’ investment in Rendezvous Gas.

 

(5) For a definition of Adjusted EBITDA and a reconciliation to the most directly comparable financial measure calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Business.”

 

(6) Includes interest expense on funds used for expansion capital expenditures, and costs incurred in connection with our new revolving credit facility, net of interest income and the amortization of deferred financing costs.

 

(7) Expansion capital expenditures are those cash expenditures incurred to increase operating capacity or operating income over the long-term. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions — Capital Expenditures.”

 

(8) Maintenance capital expenditures are those cash expenditures incurred to maintain operating capacity or operating income over the long-term. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Capital Expenditures.”

Assumptions and Considerations

Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate the minimum estimated cash available for distribution to pay the total annualized minimum quarterly distribution to all unitholders for the twelve months ending June 30, 2014. We believe the assumptions and estimates we have made to demonstrate our ability to generate our estimated cash available for distribution are reasonable, but are inherently uncertain, and actual results may differ materially.

General Considerations and Sensitivity Analysis

 

   

Actual throughput volume is the primary factor that will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2014 is above or below our forecast. Our estimates do not assume any incremental revenue, expenses or other costs associated with potential future acquisitions. If all other assumptions are held constant, a 5.0% decline in volumes below forecasted levels would result in a $5.3 million decline in cash available for distribution. A decline in forecasted cash flow of greater than $         would result in our generating less than the minimum cash required to pay distributions on the outstanding units at the initial distribution rate for the forecast period.

 

   

Historically, the fee-based services we provide to QEP in the Pinedale Field have accounted for a significant portion of our total throughput volumes and total revenue. We expect that production from QEP in the Pinedale Field will continue to be our primary growth driver going forward, and for the twelve months ended June 30, 2014, we expect that approximately 60% of our total natural gas throughput and approximately 75% of our total revenue will be directly attributable to QEP’s owned or controlled production in the Pinedale Field.

 

   

For the twelve months ending June 30, 2014, we forecast gathering and transportation volumes to be 302.6 million MMBtu compared to 309.2 million MMBtu for the year ended December 31, 2012. We expect a slight decline in production from the Pinedale field resulting from reduced drilling activity by QEP. During 2012, QEP operated six drilling rigs in the Pinedale Field, but in 2013 QEP reduced the number of operated rigs to four. While the rig count is lower, QEP expects to complete approximately the same number of wells during the twelve months ended June 30, 2014 as it did for the year ended December 31, 2012 as a result of more efficient drilling and completion operations. The assumptions and considerations included in this forecast are based on a four-rig drilling program throughout the term of the forecast. In addition, we expect some decrease in throughput as a result of natural decline in other producing fields that are forecasted to have limited drilling activity.

 

 

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Certain of our gathering systems may be affected by ongoing litigation between Questar and QEP Field Services. The dispute relates to the gathering rate being charged under a 1993 gathering agreement, which is calculated on a cost-of-service basis. Currently, Questar is paying QEP Field Services a reduced fee and is posting a security bond with respect to the disputed amount. The forecast excludes the disputed fee amount; however, the disputed amount of approximately $1.3 million was included for the first quarter of 2012 for purposes of calculating the unaudited pro forma cash available for distribution for the year ended December 31, 2012. Please read “Risk Factors — Risks Related to Our Business — From Time to Time, We are Involved in Litigation, Claims and Other Proceedings that Could Have a Material Adverse Effect on Our Business, Results of Operations, Financial Condition and Ability to Make Cash Distributions to Our Unitholders” and “Business — Legal Proceedings.”

Total Revenue

We estimate that our total revenue for the twelve months ending June 30, 2014, will be $126.3 million, as compared to $126.7 million for the pro forma year ended December 31, 2012. Our estimated total revenue for the twelve months ending June 30, 2014 is based on the following assumptions:

Gathering and Transportation

Gas gathering volumes.    We estimate that we will gather and transport an average of 302.6 million MMBtu of natural gas for the twelve months ending June 30, 2014, compared to 309.2 million MMBtu for the year ended December 31, 2012. The expected decrease in natural gas throughput for the twelve months ending June 30, 2014 is primarily due to QEP’s decreased drilling activity in the Pinedale Field and the natural production declines from the wells connected to our systems.

Gas gathering volumes for unconsolidated affiliates.    We estimate that our percentage of Three Rivers Gathering’s throughput volumes will be 24.2 million MMBtu of natural gas for the twelve months ending June 30, 2014, compared to 25.7 million MMBtu for the year ended December 31, 2012. The expected decrease in natural gas throughput for the twelve months ending June 30, 2014 is primarily due to a disruption from a third-party shipper caused by a fire at one of the shipper’s compression stations and the natural production declines from the wells connected to the Three Rivers Gathering System.

Gas gathering fees.    We estimate that we will receive an average gas gathering fee of $0.34 per MMBtu for the twelve months ending June 30, 2014, compared to $0.32 per MMBtu for the year ended December 31, 2012. The expected increase in our gathering fees is primarily due to increased contributions from contracts with higher fee structures and inflation adjustments in our gas gathering agreements.

Gas gathering revenue.    We estimate that gas gathering revenue will be $101.6 million, representing approximately 80% of our total revenues, for the twelve months ending June 30, 2014, compared to $100.5 million, representing approximately 80% of our total revenues for the pro forma year ended December 31, 2012. Approximately 50% of our historical gas gathering revenue is attributable to long-term agreements we have with QEP. The expected increase in gas gathering revenue is primarily due to increased contributions from contracts with higher fee structures, inflation adjustments and deficiency payments related to minimum volume commitments, partially offset by QEP’s decreased drilling activity in the Pinedale Field .

Crude oil and condensate gathering volumes.    We estimate that we will gather and transport an average of 5,056 MBbls of crude oil for the twelve months ending June 30, 2014, compared to 5,297 MBbls for the pro forma year ended December 31, 2012. The expected decrease in volumes for the twelve months ending June 30, 2014 is primarily due to QEP’s decreased drilling activity in the Pinedale Field and the natural production declines from the wells connected to our systems.

Crude oil and condensate gathering fees.    We estimate that we will receive an average gathering fee of $2.08 per barrel of crude oil for the twelve months ending June 30, 2014, compared to $2.11 per barrel for the year ended December 31, 2012. The expected decrease in our gathering fees is primarily due to increased contributions from contracts with lower fee structures.

 

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Crude oil and condensate gathering revenue.    We estimate that crude oil and condensate gathering revenue will be $10.5 million, representing 8% of our total revenues for the twelve months ending June 30, 2014, compared to $11.2 million, representing 9% of our total revenues, for the pro forma year ended December 31, 2012. The expected decrease in crude oil and condensate gathering revenue is primarily due to QEP’s decreased drilling activity in the Pinedale Field and the natural production declines from the wells connected to our systems.

Condensate Sales

We estimate that revenue from condensate sales will be $7.5 million, representing 6% of our total revenues for the twelve months ended June 30, 2014, compared to $7.7 million, representing 6% of our total revenues for the pro forma year ended December 31, 2012. Revenue from condensate sales is relatively flat due to increased condensate sales volumes related to our Vermillion Gathering System, partially offset by a lower forecasted sales price per barrel of condensate.

Gathering Expense

We estimate that gathering expense for the twelve months ending June 30, 2014 will be $22.8 million, compared to $21.1 million for the pro forma year ended December 31, 2012. The expected increase in gathering expense is primarily due to increases in personnel needed to operate and manage our assets and businesses and inflationary increases in costs of labor. Gathering expense is comprised primarily of direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf under our omnibus agreement.

General and Administrative Expense

We estimate that our general and administrative expense will be approximately $15.6 million for the twelve months ending June 30, 2014, compared to pro forma general and administrative expenses of $14.5 million for the pro forma year ended December 31, 2012. The pro forma numbers do not include $2.5 million of estimated expenses that we expect to incur as a result of being a publicly traded partnership. Excluding the incremental $2.5 million in general and administrative expense for the forecast period, general and administrative expense decreased because it is expected that the executive officers of our general partner will need to devote less time managing the partnership during the forecast period as compared to the year ended December 31, 2012 and during the initial public offering process. For more information regarding the general and administrative expense allocation, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Business — Operating Expenses — General and Administrative Expenses.”

Depreciation and Amortization Expense

We estimate that depreciation and amortization expense for the twelve months ending June 30, 2014 will be $32.0 million, compared to $30.6 million for the year ended December 31, 2012. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The expected increase in depreciation and amortization is primarily attributable to a full year of depreciation taken on a condensate stabilizer, additional gas compression installed on our Vermillion Gathering System and the expansion of gathering lines on our Green River and Williston gathering systems.

 

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Income from Unconsolidated Affiliate

We estimate that the equity income from our 50% investment in Three Rivers Gathering will be approximately $2.8 million for the twelve months ending June 30, 2014, compared to pro forma equity income of $3.5 million for the year ended December 31, 2012. The decrease in our forecasted equity income is primarily attributable to the expiration of the minimum volume commitments in connection with a transportation contract and a disruption from a third-party shipper caused by a fire at one of the shipper’s compression stations, partially offset by increased fees in connection with existing contracts.

Net Income Attributable to Noncontrolling Interest

We own a 78% interest in Rendezvous Gas and the remaining 22% interest is held by Western Gas. We estimate that the net income attributable to Western Gas will be $3.3 million for the twelve months ending June 30, 2014, compared to net income attributable to Western Gas of $3.7 million for the year ended December 31, 2012. The decrease in the net income attributable to Western Gas is primarily attributable to decreased throughput for Rendezvous Gas and an increase in operating expenses.

Financing

Cash.    At the closing of this offering and after using a portion of the net proceeds of this offering to repay all of our $         million of outstanding debt and to pay expenses of $         million as described in “Use of Proceeds,” we expect to have no outstanding indebtedness and cash on hand of approximately $         million, which we believe will be sufficient to fund our anticipated maintenance and expansion capital expenditures during the forecast period. We expect that our future sources of liquidity, including cash flow from operations and available borrowing capacity under our new revolving credit facility, will be sufficient to fund future capital expenditures.

Indebtedness.    For purposes of our forecast for the twelve months ending June 30, 2014, we have assumed that the closing of this offering takes place on                     , 2013. Accordingly, we have assumed that our new $         million revolving credit facility remains undrawn during the forecast period other than for working capital purposes and that our expansion capital expenditures are financed with cash on hand. We also expect that any unused portion of the new revolving credit facility will be subject to a commitment fee.

Interest expense.    We estimate that total interest expense will be approximately $2.6 million for the twelve months ending June 30, 2014, compared to pro forma interest expense of $2.5 million for the year ended December 31, 2012. Our forecasted interest expense for the twelve months ending June 30, 2014 is based on the assumption that our credit facility will be used for general working capital purposes during the forecast period. Our assumptions include commitment fees on any undrawn portion of our credit facility and a LIBOR-based interest rate on borrowings with a leverage-based pricing grid comparable to similar midstream master limited partnership.

Capital Expenditures

We estimate that total capital expenditures will be approximately $11.0 million for the twelve months ending June 30, 2014, compared to pro forma capital expenditures of $29.6 million for the year ended December 31, 2012. Our forecast estimate is based on the following assumptions:

Expansion Capital Expenditures.    For the year ended December 31, 2012, we spent approximately $19.2 million on expansion capital expenditures in connection with installing new gathering lines on our Williston Gathering System and gathering lines and a condensate stabilizer on our Vermillion Gathering System. Although, we do not anticipate having any expansion capital expenditures during the twelve months ending June 30, 2014, we continually review expansion opportunities and may have expansion capital expenditures in the future.

Maintenance Capital Expenditures.    Historically, we did not make a distinction between maintenance and expansion capital expenditures. Our estimate that maintenance capital expenditures will

 

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be approximately $11.0 million for the twelve months ending June 30, 2014 reflects our management’s judgment of the amount of capital that will be needed to maintain the current throughput across our systems and the current operating capacity of our assets for the long-term. The estimated maintenance capital expenditures relate primarily to compressor replacements and overhauls on our Green River System and Vermillion Gathering System.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2014 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.

 

   

There will not be any major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions.

 

   

There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we rely.

 

   

We will not make any acquisitions or other significant expansion capital expenditures (other than as described above).

 

   

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

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

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, within 45 days after the end of each quarter beginning with the quarter ending                     , 2013, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through                     , 2013 based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

 

   

less, the amount of cash reserves established by our general partner to:

 

   

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);

 

   

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 distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

   

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, 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 and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources — Credit Facility” for a discussion of the restrictions included in our revolving credit facility that may restrict our ability to make distributions.

 

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General Partner Interest and Incentive Distribution Rights

Initially, our general partner will be entitled to 2.0% of all quarterly distributions from inception that we make prior to our liquidation. This general partner interest will be represented by                     general partner 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. The general partner’s initial 2.0% interest in these distributions will 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 2.0% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner or its affiliates may receive on common, subordinated or general partner units that they own. Please read “— General Partner Interest and Incentive Distribution Rights” for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

   

$         million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge 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 hedge; plus

 

   

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

   

cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term

 

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borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, and (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein 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 and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized at the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

 

   

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

   

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

 

   

expansion capital expenditures;

 

   

payment of transaction expenses (including taxes) relating to interim capital transactions;

 

   

distributions to our partners;

 

   

repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

 

   

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities;

 

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

 

   

capital contributions received.

Characterization of Cash Distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us 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. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $         million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long term. Maintenance capital expenditures include well connections, or the replacement, improvement or expansion of existing capital assets, including the construction or development of new capital assets, to replace expected reductions in hydrocarbons available for gathering handled by our gathering systems. Other examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines and compression equipment, to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations.

Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include the acquisition of equipment from QEP or third parties and the construction or development of additional pipeline capacity, well connections or compression, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of.

Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Subordinated Units and Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         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

 

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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 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

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after                     , 2016, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $         (the annualized 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 annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

 

   

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

Early Termination of the Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending                     , 2014, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $         (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

 

   

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $         (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

 

   

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

Expiration Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

 

   

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;

 

   

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

 

   

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

 

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Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

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 established in prior periods. Adjusted operating surplus for a period consists of:

 

   

operating surplus generated with respect to that period (excluding any amount attributable to the item described in the first bullet of the definition of operating surplus); less

 

   

any net increase in working capital borrowings with respect to that period; less

 

   

any net decrease in cash reserves for operating expenditures 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 with respect to that period; plus

 

   

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

 

   

any net increase in cash reserves for operating expenditures 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

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

   

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

   

second, 98.0% to the common unitholders, pro rata, and 2.0% to our 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, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated 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 2.0% 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

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our 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.

 

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The preceding discussion is based on the assumptions that our general partner maintains its 2.0% 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 2.0% 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 in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units in this offering, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. Our general partner may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) 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 2.0% general partner interest, and that our general partner continues to own the incentive distribution rights.

If for any quarter:

 

   

we have distributed available cash from operating surplus to the common unitholders 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, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

   

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

   

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the 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 target amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly

 

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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 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 

     Total Quarterly Distribution
Per Unit Target Amount
     Marginal Percentage Interest in
Distributions
 
        Unitholders     General Partner  

Minimum Quarterly Distribution

   $                                   

First Target Distribution

   above $                up to $                                       

Second Target Distribution

   above $                up to $                                       

Third Target Distribution

   above $                up to $                                       

Thereafter

   above $                                          

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. 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, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. 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 payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common 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 immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

 

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The number of common 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 the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to 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, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

 

   

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

 

   

third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) 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 fiscal quarters immediately preceding the reset election was $        .

 

   

Quarterly Distribution
Per Unit Prior to Reset

  Marginal Percentage
Interest in Distributions
   

Quarterly Distribution Per Unit
Following Hypothetical Reset

    Common
Unitholders
    General
Partner
Interest
    Incentive
Distribution
Rights
   

Minimum Quarterly Distribution

              $                            2.0         $               

First Target Distribution

  above $           up to $                          2.0         above $                up to $        (1)

Second Target Distribution

  above $           up to $                          2.0     13.0   above $        (1)    up to $        (2)

Third Target Distribution

  above $           up to $                          2.0     23.0   above $        (2)    up to $        (3)

Thereafter

  above $                            2.0     48.0   above $        (3)   

 

(1) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

 

(2) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

 

(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be                      common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $         per quarter for the two consecutive non-overlapping quarters prior to the reset.

 

   

Quarterly
Distribution Per
Unit Prior to Reset

  Cash
Distributions
to Common
Unitholders
Prior to
Reset
    Cash Distribution to General
Partner Prior to Reset
    Total
Distributions
 
      Common
Units
    2.0%
General
Partner
Interest
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $             $               $              $               $              $               $            

First Target Distribution

  above $           up to $                    

Second Target Distribution

  above $           up to $                    

Third Target Distribution

  above $           up to $                    

Thereafter

  above $                      
      $               $              $               $               $               $            

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be                      common units outstanding, our general partner has maintained its 2.0% general partner interest, and that the average distribution to each common unit would be $            . The number of common units issued as a result of the reset was calculated by dividing (x)                      as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $            .

 

   

Quarterly
Distribution Per
Unit After Reset

  Cash
Distributions
to Common
Unitholders
After Reset
    Cash Distribution to General
Partner After Reset
    Total
Distributions
 
      Common
Units
    2.0%
General
Partner
Interest
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $             $               $               $               $              $               $            

First Target Distribution

  above $           up to $                    

Second Target Distribution

  above $           up to $                    

Third Target Distribution

  above $           up to $                    

Thereafter

  above $                      
      $               $               $               $              $               $            

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 immediately preceding four consecutive fiscal 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

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

   

first, 98.0% to all unitholders, pro rata, and 2.0% to our 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 in this offering;

 

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second, 98.0% to all unitholders, pro rata, and 2.0% to our 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 outstanding common units; and

 

   

thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% 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 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, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 2.0% to our general partner and 48.0% to the holder of our 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, we will proportionately adjust:

 

   

the minimum quarterly distribution;

 

   

target distribution levels;

 

   

the unrecovered initial unit price;

 

   

the number of general partner units comprising the general partner interest; and

 

   

the arrearages in payment of the minimum quarterly distribution on the common units.

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 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental 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 the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) 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 may be accounted for in subsequent quarters.

 

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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 the 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 our partners in the following manner:

 

   

first, to our general partner to the extent of any negative balance in its capital account;

 

   

second, 98.0% to the common unitholders, pro rata, and 2.0% to our 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, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our 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, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to:

 

  (1) the sum of the excess of the first target 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 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

 

   

fifth, 85.0% to all unitholders, pro rata, and 15.0% to our 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

 

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  (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 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

 

   

sixth, 75.0% to all unitholders, pro rata, and 25.0% to our 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 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;

 

   

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

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 fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 

   

first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

   

second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

   

thereafter, 100.0% to our 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 resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain 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 generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the

 

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subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

Our Predecessor consists of all of QEP’s gathering assets in the Green River, Uinta and Williston Basins, including (i) a 100% interest in each of Green River Gathering, Rendezvous Pipeline, Vermillion Gathering and Williston Gathering, (ii) a 78% interest in Rendezvous Gas, (iii) a 50% equity interest in Three Rivers Gathering, (iv) a 38% equity interest in Uintah Basin Field Services and (v) a 100% interest in all other QEP gathering assets and operations that QEP conducts in the Uinta Basin (referred to as the Uinta Basin Gathering System). The following table presents, in each case for the periods and as of the dates indicated, selected historical combined financial and operating data of our Predecessor and selected pro forma combined financial and operating data of QEP Midstream Partners, LP.

The selected historical combined financial and operating data of our Predecessor as of and for the years ended December 31, 2012 and 2011 are derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus.

The selected pro forma combined financial data presented in the following table as of and for the year ended December 31, 2012 are derived from the unaudited pro forma combined financial data included elsewhere in this prospectus. The pro forma combined financial data assumes that the transactions described under “Prospectus Summary — Formation Transactions and Partnership Structure” occurred as of January 1, 2012. These transactions primarily include, and the pro forma financial data give effect to, the following:

 

   

the contribution of (i) 100% of the ownership interests in each of Green River Gathering, Rendezvous Pipeline, Vermillion Gathering and Williston Gathering, (ii) a 78% interest in Rendezvous Gas, and (iii) a 50% equity interest in Three Rivers Gathering;

 

   

QEP’s retention of the Uinta Basin Gathering System and its 38% interest in Uintah Basin Field Services, which will not be contributed to us;

 

   

our entry into a new $         million revolving credit facility;

 

   

our entry into an omnibus agreement with QEP;

 

   

the issuance of                     common units and                     subordinated units; and

 

   

the application of the $         million in net proceeds from this offering as described in “Use of Proceeds.”

The pro forma combined financial data does not give effect to the estimated $2.5 million in incremental annual general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of our Predecessor and the notes thereto and our unaudited pro forma combined financial statements and the notes thereto, in each case included elsewhere in this prospectus. Among other things, those historical and pro forma combined financial statements include more detailed information regarding the basis of presentation for the information in the following table. Our financial position, results of operations and cash flows could differ from those that would have resulted if we operate autonomously or as an entity

 

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independent of QEP in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

 

     QEP Midstream
Partners, LP
Predecessor
    QEP Midstream
Partners, LP
Pro Forma
 
     Year Ended
December  31,
    Year Ended
December  31,
 
     2011     2012     2012  
    

(in millions, except

per unit amounts)

 

Statement of Operations

      

Revenues

   $ 155.9      $ 161.4      $ 126.7   

Operating Expenses:

      

Gathering expense

     27.7        29.9        21.1   

General and administrative(1)

     15.3        19.4        14.5   

Taxes other than income taxes

     2.8        3.1        2.1   

Depreciation and amortization

     38.3        39.8        30.6   
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     84.1        92.2        68.3   
  

 

 

   

 

 

   

 

 

 

Operating income

     71.8        69.2        58.4   

Other income

     0.1        0.1        0.1   

Income from unconsolidated affiliates

     4.4        7.2        3.5   

Interest expense

     (12.8     (8.7     (2.5
  

 

 

   

 

 

   

 

 

 

Net income

     63.5        67.8        59.5   

Net income attributable to noncontrolling interest

     (3.2     (3.7     (3.7
  

 

 

   

 

 

   

 

 

 

Net income attributable to Predecessor or us

   $ 60.3      $ 64.1      $ 55.8   
  

 

 

   

 

 

   

 

 

 

General partner’s interest in net income

      

Limited partner’s interest in net income

      

Common units

      

Subordinated units

      

Net income per limited partner unit

      

Common units

      

Subordinated units

      

Balance Sheet

      

Property, plant and equipment, net

   $ 629.1      $ 634.1      $ 503.9   

Total assets

     714.3        724.6        573.8   

Long-term debt to related party

     174.6        134.2          

Statement of Cash flows

      

Net cash provided by operating activities

   $ 97.5      $ 104.5     

Capital expenditures

     (28.6     (43.7  

Net cash used in investing activities

     (28.5     (43.4  

Net cash used in financing activities

     (68.0     (62.2  

 

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     QEP Midstream
Partners, LP
Predecessor
    QEP Midstream
Partners, LP
Pro Forma
 
     Year Ended
December  31,
    Year Ended
December  31,
 
     2011     2012     2012  
    

(in millions, except

per unit amounts)

 

Operating information

      

Natural gas throughput in millions of MMBtu

      

Gathering and transportation

     384.7        387.8        309.2   

Equity interest(2)

     34.4        27.5        25.7   
  

 

 

   

 

 

   

 

 

 

Total natural gas throughput

     419.1        415.3        334.9   

Throughput attributable to noncontrolling interests(3)

     (14.3     (12.1     (12.1
  

 

 

   

 

 

   

 

 

 

Total throughput attributable to our Predecessor or us

     404.8        403.2        322.8   
  

 

 

   

 

 

   

 

 

 

Average gas gathering and transportation fee (per MMBtu)

   $ 0.30      $ 0.34      $ 0.32   

Crude oil and condensate gathering system throughput volumes (in MBbls)

     4,105.4        5,297.4        5,297.4   

Average oil and condensate gathering fee (per barrel)

   $ 1.89      $ 2.11      $ 2.11   

Non-GAAP Measures

      

Adjusted EBITDA(4)

   $ 109.6      $ 109.7      $ 86.0   

 

(1) Pro forma and general administrative expenses do not give effect to annual incremental general and administrative expenses of approximately $2.5 million that we expect to incur as a result of being a publicly traded partnership. For more information regarding the general and administrative expense allocation, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Business — Operating Expenses — General and Administrative Expenses.”

 

(2) Includes our 50% share of gross volumes from Three Rivers Gathering and our 38% share of gross volumes from Uintah Basin Field Services.

 

(3) Includes the 22% noncontrolling interest in Rendezvous Gas.

 

(4) For a discussion of Adjusted EBITDA, please read “— Non-GAAP Financial Measures” below.

Non-GAAP Financial Measures

We define Adjusted EBITDA as net income attributable to our Predecessor or us before the following items: depreciation and amortization, interest and other income, interest expense and deferred revenue associated with minimum volume commitment payments. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and commercial banks, to assess:

 

   

our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;

 

   

the ability of our assets to generate sufficient cash flow to make distributions to our partners;

 

   

our ability to incur and service debt and fund capital expenditures; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to our Predecessor or us and cash flow from

 

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operating activities. Adjusted EBITDA should not be considered an alternative to net income attributable to our Predecessor or us, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income attributable to our Predecessor or us, and these measures may vary among other companies. As a result, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to net income attributable to our Predecessor or us and cash flow from operating activities, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

       QEP Midstream Partners, LP
Predecessor combined
     QEP Midstream
Partners, LP
Pro forma
 
       2011        2012      2012  
       (in millions)  

Reconciliation of Net Income Attributable to Our Predecessor or Us to Adjusted EBITDA

            

Net income attributable to our Predecessor or us

     $ 60.3         $ 64.1       $ 55.8   

Other income

       (0.1        (0.1      (0.1

Interest expense

       12.8           8.7         2.5   

Depreciation and amortization(1)

       35.6           37.0         27.8   

Deferred revenue associated with minimum volume commitment payments(2)

       1.0                     
    

 

 

      

 

 

    

 

 

 

Adjusted EBITDA

     $ 109.6         $ 109.7       $ 86.0   
    

 

 

      

 

 

    

 

 

 

Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA

            

Net cash provided by operating activities

     $ 97.5         $ 104.5      

Noncontrolling interest share of depreciation and amortization

       (2.7        (2.8   

Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates

       (3.3        (0.6   

Net income attributable to noncontrolling interest

       (3.2        (3.7   

Interest expense

       12.8           8.7      

Deferred revenue associated with minimum volume commitment payments(2)

       1.0                

Other income

       (0.1        (0.1   

Working capital changes

       7.6           3.7      
    

 

 

      

 

 

    

Adjusted EBITDA

     $ 109.6         $ 109.7      
    

 

 

      

 

 

    

 

(1) Excludes the noncontrolling interest’s 22% share, or $2.8 million and $2.7 million during the years ended December 31, 2012 and 2011, respectively, in depreciation and amortization attributable to Rendezvous Gas Services.
(2)

Several of our contracts contain minimum volume commitments that allow us to charge the customer a deficiency payment if the customer’s actual throughput volumes are less than its minimum volume commitment for the applicable period. In certain contracts, if a customer makes a deficiency payment, that customer may be entitled to offset gathering fees in one or more subsequent periods to the extent that such customer’s throughput volumes in those periods exceed its minimum volume commitment. Depending on the specific terms of the contract, for GAAP accounting purposes, revenue under these

 

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  agreements may be classified as deferred revenue and recognized once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired or lapsed through the passage of time pursuant to the terms of the applicable agreement. Deficiency payments that are recorded as deferred revenue are included in the calculation of our Adjusted EBITDA and cash available for distribution in the period in which the deficiency payment is recorded rather than when they are recognized as revenue on the Consolidated Statement of Income.

 

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the historical combined financial statements and notes of our Predecessor and our pro forma combined financial data included elsewhere in this prospectus. Among other things, those historical combined financial statements and pro forma combined data include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included elsewhere in this prospectus.

Overview

We are a limited partnership recently formed by QEP Resources, Inc. (NYSE: QEP) to own, operate, acquire and develop midstream energy assets. Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota, which are currently among the most economic and active drilling regions in the United States. As of and for the year ended December 31, 2012, our gathering systems had 1,475 miles of pipeline and average gross throughput of 1.8 million MMBtu/d of natural gas and 18,224 Bbls/d of crude oil. Our customers are some of the largest natural gas producers in the Rocky Mountain region, including QEP, Anadarko Petroleum Corporation (Anadarko), EOG Resources, Inc. (EOG), Questar Corporation (Questar) and Ultra Resources, Inc. (Ultra).

Our Operations

Our results are driven primarily by the volumes of oil and natural gas we gather and the fees assessed for such services. We connect wells to gathering lines through which (i) oil may be delivered to a downstream pipeline and ultimately to end-users and (ii) natural gas may be delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end-users.

We generally do not take title to the oil and natural gas that we gather or transport. We provide all of our gathering services pursuant to fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Under these arrangements, we are paid a fixed or margin-based fee with respect to the volume of the oil and natural gas we gather. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. In addition to our fee-based gathering services, we generate approximately 6% of our revenue through the sale of condensate volumes that we collect on our gathering systems. We have some indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of oil and natural gas available for gathering by our systems. Please read “— Quantitative and Qualitative Disclosures About Market Risk” below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

We have secured significant acreage dedications from several of our largest customers, including QEP. We believe that drilling activity on acreage dedicated to us should maintain or increase our existing throughput levels and offset the natural production declines of the wells currently connected to our gathering systems. Specifically, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering contract and located within the dedicated acreage as our gathering systems currently exist and as they are expanded to connect to additional wells.

 

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We provide a significant portion of our transportation services on our Three Rivers, Vermillion and Williston gathering systems through firm contracts with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. Our Predecessor’s and our largest customer is QEP, which accounted for approximately 49% of our Predecessor’s total revenues and 52% of our total pro forma revenues, respectively, for the year ended December 31, 2012. For a discussion regarding our minimum volume commitments, please read “Business — Our Assets and Operations — Minimum Volume Commitments.”

How We Evaluate Our Business

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes; (ii) operating expenses; (iii) Adjusted EBITDA and (iv) distributable cash flow.

Throughput volumes

The amount of revenue we generate primarily depends on the volumes of natural gas and crude oil that we gather for our customers. The volumes transported on our gathering pipelines are pr