QEP Midstream Partners, LP - FORM S-1/A

QEP Midstream Partners, LP - FORM S-1/A - July 3, 2013

Attached files

Attached files

file	filename
EX-10.4 - EX-10.4 - QEP Midstream Partners, LP	d526933dex104.htm
EX-21.1 - EX-21.1 - QEP Midstream Partners, LP	d526933dex211.htm
EX-10.9 - EX-10.9 - QEP Midstream Partners, LP	d526933dex109.htm
EX-10.3 - EX-10.3 - QEP Midstream Partners, LP	d526933dex103.htm
EX-10.8 - EX-10.8 - QEP Midstream Partners, LP	d526933dex108.htm
EX-23.1 - EX-23.1 - QEP Midstream Partners, LP	d526933dex231.htm
EX-10.6 - EX-10.6 - QEP Midstream Partners, LP	d526933dex106.htm
EX-10.11 - EX-10.11 - QEP Midstream Partners, LP	d526933dex1011.htm
EX-10.10 - EX-10.10 - QEP Midstream Partners, LP	d526933dex1010.htm
EX-10.12 - EX-10.12 - QEP Midstream Partners, LP	d526933dex1012.htm
EX-10.7 - EX-10.7 - QEP Midstream Partners, LP	d526933dex107.htm

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 3, 2013

Registration No. 333-188487

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

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 17^th 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 17^th 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):

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.

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 JULY 3, 2013

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 23.

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.

•

There is no existing market for our common units, and a trading market that will provide unitholders with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

•

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.” The structuring fee will be paid to Wells Fargo Securities, LLC from the net proceeds of this offering. Please read “Use of Proceeds.”

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.

LOGO

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			11
Ownership and Organizational Structure of QEP Midstream Partners, LP			12
Management of QEP Midstream Partners, LP			13
Principal Executive Offices and Internet Address			13
Summary of Conflicts of Interest and Duties			13
THE OFFERING			15
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			20
RISK FACTORS			23
Risks Related to Our Business			23
Risks Inherent in an Investment in Us			42
Tax Risks			51
USE OF PROCEEDS			56
CAPITALIZATION			57
DILUTION			58
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			59
General			59
Our Minimum Quarterly Distribution			61
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013			63
Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2014			65
Assumptions and Considerations			68
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			73
Distributions of Available Cash			73
Operating Surplus and Capital Surplus			74
Capital Expenditures			76
Subordinated Units and Subordination Period			76
Distributions of Available Cash from Operating Surplus During the Subordination Period			78
Distributions of Available Cash from Operating Surplus After the Subordination Period			78
General Partner Interest and Incentive Distribution Rights			79
Percentage Allocations of Available Cash from Operating Surplus			79
General Partner’s Right to Reset Incentive Distribution Levels			80
Distributions from Capital Surplus			82
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			83
Distributions of Cash Upon Liquidation			84
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			87
Non-GAAP Financial Measures			89
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			92
Overview			92
Our Operations			92
How We Evaluate Our Business			93
General Trends and Outlook			94
Factors Affecting the Comparability of Our Financial Results			96
Results of Operations			97


Liquidity and Capital Resources			99
Off-Balance Sheet Arrangements			103
Credit Risk			103
Contractual Cash Obligations and Other Commitments			104
Critical Accounting Policies and Estimates			104
Quantitative and Qualitative Disclosures About Market Risk			106
INDUSTRY OVERVIEW			107
General			107
Natural Gas Midstream Services			108
Crude Oil Gathering and Transportation			109
Contractual Arrangements			110
U.S. Natural Gas Fundamentals			111
BUSINESS			113
Overview			113
Business Strategies			114
Competitive Strengths			114
Our Assets and Operations			116
Our Relationship with QEP Resources, Inc.			128
Competition			130
Seasonality			130
Insurance			130
Safety and Maintenance			131
Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service			133
Environmental Matters			136
Title to Properties and Permits			143
Employees			144
Legal Proceedings			144
MANAGEMENT			145
Management of QEP Midstream Partners, LP			145
Directors and Executive Officers of QEP Midstream Partners GP, LLC			146
Board Leadership Structure			148
Board Role in Risk Oversight			148
Executive Compensation			148
Long-Term Incentive Plan			149
Other Policies			151
Director Compensation			152
SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			153
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			154
Distributions and Payments to Our General Partner and Its Affiliates			154
Agreements Governing the Transactions			155
Other Agreements with QEP and Related Parties			157
Procedures for Review, Approval and Ratification of Related Person Transactions			157
CONFLICTS OF INTEREST AND DUTIES			159
Conflicts of Interest			159
Duties of the General Partner			164
DESCRIPTION OF THE COMMON UNITS			168
The Units			168
Transfer Agent and Registrar			168
Transfer of Common Units			168
OUR PARTNERSHIP AGREEMENT			170
Organization and Duration			170
Purpose			170
Capital Contributions			170


Voting Rights			170
Limited Liability			172
Issuance of Additional Securities			173
Amendment of Our Partnership Agreement			173
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			175
Termination and Dissolution			176
Liquidation and Distribution of Proceeds			176
Withdrawal or Removal of Our General Partner			176
Transfer of General Partner Interest			178
Transfer of Ownership Interests in Our General Partner			178
Transfer of Incentive Distribution Rights			178
Change of Management Provisions			178
Limited Call Right			178
Redemption of Ineligible Holders			179
Meetings; Voting			179
Status as Limited Partner			180
Indemnification			180
Reimbursement of Expenses			181
Books and Reports			181
Right to Inspect Our Books and Records			181
Registration Rights			181
Exclusive Forum			182
UNITS ELIGIBLE FOR FUTURE SALE			183
Rule 144			183
Our Partnership Agreement and Registration Rights			183
Lock-Up Agreements			184
Registration Statement on Form S-8			184
MATERIAL FEDERAL INCOME TAX CONSEQUENCES			185
Partnership Status			186
Limited Partner Status			187
Tax Consequences of Unit Ownership			187
Tax Treatment of Operations			193
Disposition of Common Units			194
Uniformity of Units			197
Tax-Exempt Organizations and Other Investors			197
Administrative Matters			198
Recent Legislative Developments			201
State, Local, Foreign and Other Tax Considerations			201
INVESTMENT IN QEP MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			203
UNDERWRITING			205
Option to Purchase Additional Common Units			205
Discounts			205
Indemnification of Underwriters			206
Lock-Up Agreements			206
Electronic Distribution			207
New York Stock Exchange			207
Stabilization			207
Discretionary Accounts			208
Pricing of This Offering			208
Relationships			208
Sales Outside the United States			208

iii


VALIDITY OF THE COMMON UNITS			210
EXPERTS			210
WHERE YOU CAN FIND ADDITIONAL INFORMATION			210
FORWARD-LOOKING STATEMENTS			211
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.”

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. Based on management’s knowledge and experience, we believe that the third-party sources cited in this prospectus are reliable and that the third-party information included in this prospectus or in our estimates is reasonably accurate and complete.

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 23 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 QEPM Gathering I, LLC, or QEPM Gathering, and (ii) a 50% interest in Three Rivers Gathering, L.L.C., or Three Rivers Gathering. QEPM Gathering will own our Vermillion and Williston gathering systems, a 100% interest in Rendezvous Pipeline Company, L.L.C., or Rendezvous Pipeline, a 78% interest in Rendezvous Gas Services, L.L.C., or Rendezvous Gas, and crude oil and natural gas gathering assets in the Pinedale and Moxa Arch fields, which we refer to as the Green River Gathering Assets. We refer to the Green River Gathering Assets and the assets owned by Rendezvous Pipeline and Rendezvous Gas as the Green River System. 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. As of and for the three months ended March 31, 2013, our gathering systems had 1,475 miles of pipeline and an average gross throughput of 1.6 million MMBtu/d of natural gas and 17,414 Bbls/d of crude oil. We believe 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).

revenue was generated through the sale of condensate volumes that we collect on our gathering systems. For the three months ended March 31, 2013, approximately 50% of our natural gas gathering volumes and approximately 33% of our crude oil volumes were comprised of production owned by QEP, making QEP our largest customer.

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 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, and we do not know when, or if, QEP will make any such offer. Please read “— Our Relationship with QEP Resources, Inc.” for additional information with respect to QEP’s portfolio of midstream assets.

For the three months ended March 31, 2013, we generated $31.0 million of revenue, $11.9 million of net income attributable to us and $19.8 million of Adjusted EBITDA. For the year ended December 31, 2012, we generated $127.5 million of revenue, $55.6 million of net income attributable to us and $86.1 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.”

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 March 31, 2013:


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 Assets	Gas Gathering		405		307		41,053		737			527
	Oil Gathering		61		93		—		7,137	(2)		3,205	(2)
	Water Gathering		81		93		—		21,990	(3)		9,668	(3)
	Oil Transmission(4)		60		6		—		40,800	(2)		10,806	(2)
Rendezvous Gas(5)	Gas Gathering		309		3		7,800		1,032			564
Rendezvous Pipeline (4)	Gas Transmission		21		1		—		460			269
Vermillion Gathering System	Gas Gathering		454		503		23,197		206			146
Three Rivers Gathering System(6)	Gas Gathering		50		8		4,735		212			65
Williston Gathering System	Gas Gathering		17		24		239		3			1
	Oil Gathering		17		24		—		7,000	(2)		3,402	(2)

Total			1,475		1,062		77,024

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2013.

(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 assets – the Green River Gathering Assets and the assets owned by 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 Assets

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 527 thousand MMBtu/d for the three months ended March 31, 2013. These assets also had average gross gathering throughput of 3,205 Bbls/d of oil and 9,668 Bbls/d of water for the three months ended March 31, 2013. Our FERC-regulated crude oil pipeline, which includes third-party, crude oil volumes not gathered on our system, had average gross throughput of 10,806 Bbls/d for the three months ended March 31, 2013.

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

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 564 thousand MMBtu/d for the three months ended March 31, 2013.

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 269 thousand MMBtu/d for the three months ended March 31, 2013. 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). For the three months ended March 31, 2013, approximately 68% of the 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 146 thousand MMBtu/d for the three months ended March 31, 2013.

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 in which QEP owns a 38% interest (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 65 thousand MMBtu/d for the three months ended March 31, 2013.

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

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 3,402 Bbls/d of crude oil for the three months ended March 31, 2013.

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:

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

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

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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. We are not currently a party to any written or unwritten agreements to purchase additional midstream assets from QEP and we do not know when QEP will offer to sell us additional assets, if at all. For a description of QEP’s retained midstream asset portfolio, please read “— Our Relationship with QEP Resources, Inc.”

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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.

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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.

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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.

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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.

Competitive Strengths

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

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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.

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Acquisition opportunities. After the closing of this offering, QEP will continue to own a substantial 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, and we do not know when, or if, QEP will make any such offer.

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QEP. QEP is actively operating in the Rocky Mountain region and as of December 31, 2012 served 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.

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Acreage Dedication. As of December 31, 2012, 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.

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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. 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.

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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.

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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.

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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. 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:

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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

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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 actively operating in several 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		54,306		299		201
Uintah Basin Field Services(2)	Uinta Basin		78		21		5,360		26		11
Haynesville Gathering System	Haynesville Shale		200		230		7,360		2,000		228

Total			887		2,197		67,026		2,325		440

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2013.

(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)

Blacks Fork Processing Complex

Green River Basin

Processing

Cryogenic /

Joule-Thomson

835

464

Fractionation

Fractionator

15,000

(2)(3)

2,671

(2)

Emigrant Trail Processing Plant

Green River Basin

Processing

Cryogenic

Vermillion Processing Plant(4)

Southern Green River Basin

Processing

Cryogenic

Uinta Basin Processing Complex

Uinta Basin

Processing

Cryogenic /

Refrigeration

650

(5)

283

Haynesville Gathering System

Haynesville Shale

Treating

600

228

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 three months ended March 31, 2013.

(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.

The midstream assets shown in the preceding table consist primarily of gathering, treating and processing assets that do not fit the profile of the assets that will be contributed to us by QEP in conjunction with this offering because they (i) require significant additional capital to be spent in the near term in order to be expanded or fully developed, (ii) have underlying contracts that increase their exposure to commodity price risk or (iii) have experienced declining throughput volumes as a result of decreased drilling activity driven by weak natural gas prices.

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:

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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;

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

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

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

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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;

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

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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.

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. The following list of risk factors should be read carefully in conjunction with the risks under the caption “Risk Factors” beginning on page 23.

Risks Related to Our Business

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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.

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Our success depends on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.

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

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Some of our gathering agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

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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 our unitholders.

Risks Inherent in an Investment in Us

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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.

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

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Tax Risks

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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.

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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.

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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.

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:

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QEP will convey its ownership interests in each of Rendezvous Pipeline and Rendezvous Gas to QEPM Gathering;

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QEP will convey its ownership interests in each of QEPM Gathering and Three Rivers Gathering to QEP Operating as a capital contribution and in exchange for QEP Operating assuming $ million of existing debt;

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

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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;

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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;

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

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

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

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

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.

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 and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will pay to QEP an annual amount for providing us with certain general and administrative services, which includes a fixed annual fee for certain executive management services by certain officers of our general partner. Other portions of the annual amount will be based on the costs actually incurred by QEP and its affiliates in providing the services. We will also reimburse QEP for any additional out-of-pocket costs and expenses incurred by QEP and its affiliates in providing general and administrative services to us. For the twelve months ending June 30, 2014, we estimate that the fees and expenses described above will be approximately $16.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement” and “Management — Executive Compensation.”

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, 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.”

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 and estimated offering expenses. We intend to use the net proceeds as follows:

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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;

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

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pay revolving credit facility origination fees of $ million; and

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pay Wells Fargo Securities, LLC a structuring fee 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:

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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

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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 and the twelve months ended March 31, 2013 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.

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 66²/₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, 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 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:

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

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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 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.”

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 QEPM Gathering and Rendezvous Pipeline, (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, 2011 and 2012 are derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus. The summary historical combined financial and operating data of our Predecessor as of March 31, 2013 and for the three months ended March 31, 2012 and 2013 are derived from the unaudited combined financial statements of our Predecessor included elsewhere in this prospectus.

The summary pro forma combined financial data presented in the following table for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013, respectively, 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 to be effected at the closing of the offering and described under “—Formation Transactions and Partnership Structure” had taken place on March 31, 2013, in the case of the pro forma balance sheet, and as of January 1, 2012, in the case of the pro forma statement of operations for the year ended December 31, 2012 and the three months ended March 31, 2013, respectively. 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 QEPM Gathering and Rendezvous Pipeline, (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, its 38% interest in Uintah Basin Field Services and general support equipment, each of 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 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” beginning on page 89. 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 — Adjusted EBITDA and Distributable Cash Flow” beginning on page 94.


	QEP Midstream Partners, LP Predecessor												QEP Midstream Partners, LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2011			2012			2012			2013			2012			2013
	(in millions)
*Statement of Operations*
Revenues	$	155.9		$	162.2		$	41.9		$	40.1		$	127.5		$	31.0
Operating Expenses:
Gathering expense		27.7			29.9			7.2			7.7			21.1			5.8
General and administrative(1)		15.3			17.0			3.6			5.7			15.2			4.5
Taxes other than income taxes		2.8			3.1			0.8			0.3			2.1			0.2
Depreciation and amortization		38.3			39.8			9.8			10.3			29.9			7.7

Total operating expenses		84.1			89.8			21.4			24.0			68.3			18.2
Loss from asset sales		—			—			—			(0.3	)		—			—

Operating income		71.8			72.4			20.5			15.8			59.2			12.8
Other income		0.1			0.1			—			—			0.1			—
Income from unconsolidated affiliates		4.4			7.2			1.9			1.3			3.5			0.6
Interest expense		(12.8	)		(8.7	)		(1.8	)		(1.1	)		(3.5	)		(0.9	)

Net income		63.5			71.0			20.6			16.0			59.3			12.5
Net income attributable to noncontrolling interest		(3.2	)		(3.7	)		(0.8	)		(0.6	)		(3.7	)		(0.6	)

Net income attributable to our Predecessor or us	$	60.3		$	67.3		$	19.8		$	15.4		$	55.6		$	11.9

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					$	625.2					$	493.1
Total assets		714.3			725.4						709.8						558.7
Long-term debt to related party		174.6			131.1						85.7						—


	QEP Midstream Partners, LP Predecessor												QEP Midstream Partners, LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2011			2012			2012			2013			2012			2013
	(in millions)
*Statement of Cash flows*
Net cash provided by operating activities	$	97.5		$	107.0		$	36.6		$	38.9
Capital expenditures		(28.6	)		(43.7	)		(11.8	)		(3.9	)
Net cash used in investing activities		(28.5	)		(43.4	)		(11.8	)		(3.1	)
Net cash used in financing activities		(68.0	)		(64.7	)		(24.3	)		(34.3	)
*Operating information*
Natural gas throughput in millions of MMBtu
Gathering and transportation		384.7			387.8			93.1			90.6			309.2			72.5
Equity interest(2)		34.4			27.5			7.2			3.3			25.7			2.9

Total natural gas throughput		419.1			415.3			100.3			93.9			334.9			75.4
Throughput attributable to noncontrolling interests(3)		(14.3	)		(12.1	)		(3.4	)		(2.6	)		(12.1	)		(2.6	)

Total throughput attributable to our Predecessor or us		404.8			403.2			96.9			91.3			322.8			72.8
Average gas gathering and transportation fee (per MMBtu)	$	0.30		$	0.34		$	0.35		$	0.36		$	0.32		$	0.34
Crude oil and condensate gathering system throughput volumes (in MBbls)		4,105.4			5,297.4			1,322.4			1,278.8			5,297.4			1,278.8
Average oil and condensate gathering fee (per barrel)	$	1.89		$	2.11		$	1.92		$	2.02		$	2.11		$	2.02
*Non-GAAP Measures*
Adjusted EBITDA (in millions)	$	109.6		$	112.9		$	30.7		$	26.4		$	86.1		$	19.8

(1)

Pro forma general and administrative expenses do not give effect to annual incremental general and administrative expenses of approximately $2.5 million, or such pro rata amount, as applicable, 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.

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;

•

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;

•

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;

•

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 and the three months ended March 31, 2013, QEP accounted for approximately 52% and 55%, respectively, 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

Field Services. As of March 31, 2013, our Predecessor has recorded $4.9 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

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 and the three months ended March 31, 2013. We have gathering contracts with each of these customers of varying

duration and commercial terms. If we were 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 and 55% and 14%, respectively, of our revenue for the three months ended March 31, 2013. 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 regulated substances or losses of oil or natural gas as a result of the malfunction of equipment or facilities;

•

ruptures, fires and explosions; and

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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 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 or operators 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:

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mistaken assumptions about volumes, revenue, costs and synergies;

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

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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;

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coordinating geographically disparate organizations, systems and facilities;

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the assumption of unknown liabilities;

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limitations on the right to indemnity from the seller;

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mistaken assumptions about the overall costs of equity or debt;

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

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

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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

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:

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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;

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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;

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

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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.

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:

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incur or guarantee additional debt;

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make distributions on or redeem or repurchase units;

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make certain investments and acquisitions;

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make capital expenditures;

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incur certain liens or permit them to exist;

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enter into certain types of transactions with affiliates;

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merge or consolidate with another company; and

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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

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, with a final report expected to be issued in 2016. 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. 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 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 use 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.

More recently, on May 24, 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface.

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 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 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:

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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;

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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;

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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;

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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;

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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;

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

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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 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:

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perform ongoing assessments of pipeline integrity;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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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 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 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. We monitor and report our GHG emissions. However, operational or regulatory changes could require additional monitoring and reporting at 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.

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

We are managed and operated by the board of directors and executive officers of our general partner. All of the personnel that conduct our business are employed by affiliates of our general partner, but we sometimes refer to these individuals as our employees. Our ability to operate our business and implement our strategies will depend on our continued ability and the ability of affiliates of our general partner 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 or affiliates of our general partner may not be able to attract and retain qualified personnel in the future, and the failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business. Neither we nor our general partner maintains key person life insurance policies for any of our senior management team.

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.

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:

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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;

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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;

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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;

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

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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;

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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;

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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;

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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;

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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;

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our general partner intends to limit its liability regarding our contractual and other obligations;

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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;

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

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

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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 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:

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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;

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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

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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.”

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 providing 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. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders. For the twelve months ending June 30, 2014, we estimate that these expenses will be approximately $16.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. For a description of the cost reimbursements to our general partner, please read “Our Partnership Agreement — Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”

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 66²/₃% 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.

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:

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our unitholders’ proportionate ownership interest in us will decrease;

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

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

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the ratio of taxable income to distributions may increase;

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

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the market price of our common units may decline.

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, 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:

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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. All of the common units held by QEP will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters, which may be waived in the discretion of certain of the underwriters. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The 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 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 Service (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 with respect to our treatment as a partnership for federal income tax purposes.

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. 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.

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 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 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.

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 and estimated offering expenses. 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;

•

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

•

pay revolving credit facility origination fees of $ million; and

•

pay Wells Fargo Securities, LLC a structuring fee of $ million.

As of March 31, 2013, QEP Operating, our wholly owned subsidiary, had approximately $114.0 million of debt outstanding, comprised of intercompany loans from QEP that bear interest at 6.05% and are due March 31, 2014 and 2017, respectively. QEP Operating assumed this intercompany debt in connection with this offering. Please read “Prospectus Summary — Formation Transactions and Partnership Structure.” The 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.”

CAPITALIZATION

The following table shows:

•

the historical cash and cash equivalents and capitalization of our Predecessor as of March 31, 2013;

•

our pro forma capitalization as of March 31, 2013, giving effect to the pro forma adjustments related to (i) QEP’s contribution to us of the equity interests in QEPM Gathering, Rendezvous Pipeline, Rendezvous Gas and Three Rivers and (ii) QEP’s retention of the Uinta Basin Gathering System, its 38% interest in Uintah Basin Field Services and general support equipment, in each case as described in our unaudited pro forma combined financial data included elsewhere in this prospectus; and

•

our pro forma as adjusted capitalization as of March 31, 2013, giving effect to, and the application of the net proceeds from, this offering and the entry into a new $ million revolving credit facility as 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 March 31, 2013
	Historical		Pro Forma		Pro Forma As Adjusted
	(in millions)
Cash and cash equivalents	$	2.9	$	2.9	$

Debt:
Long-term debt	$	85.7	$	114.0	$
Revolving credit facility		—		—

Total long-term debt (including current maturities)		85.7		114.0

Net investment/equity:
Net investment		532.5		362.7
Common Units — public		—		—
Common Units — QEP		—		—
Subordinated Units — QEP		—		—
Noncontrolling interest		46.8		46.8
General partner equity		—		—

Total equity	$	579.3	$	409.5	$

Total capitalization	$	665.0	$	523.5	$

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 March 31, 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 March 31, 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		$

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

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. For the twelve months ending June 30, 2014, we estimate that our general and administrative expenses will be approximately $16.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Available Cash,” “Our Partnership Agreement — Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”

•

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 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:

No Exercise of Option to Purchase
Additional Common Units

Full Exercise of Option to Purchase
Additional Common Units

Minimum Quarterly
Distributions

(in millions)

Number of Units

One Quarter

Annualized
(Four
Quarters)

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

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 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 and the Twelve Months Ended March 31, 2013,” 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 and the twelve months ended March 31, 2013, respectively, 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.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013

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 $70.8 million and $68.2 million for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. These amounts 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 periods.

Our unaudited pro forma available cash for the year ended December 31, 2012 and the twelve months ended March 31, 2013 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.

The adjusted amounts below do not present our results of operations as if the transactions contemplated in this prospectus had actually been completed on January 1, 2012 or April 1, 2012, respectively. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical combined financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on January 1, 2012 or April 1, 2012.

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.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2012 and the twelve months ended March 31, 2013, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering had been completed on January 1, 2012 or April 1, 2012. 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


	Twelve Months Ended March 31, 2013		Year Ended December 31, 2012
	(in millions, except per unit data)
Pro Forma Net Income Attributable to Us	$	51.1	$	55.6
Add:
Depreciation and amortization, net of noncontrolling interest(1)		27.6		27.1
Interest expense, net		3.5		3.4

Pro Forma Adjusted EBITDA(2)	$	82.2	$	86.1

Less:
Incremental general and administrative expenses associated with being a publicly traded partnership(3)		2.5		2.5
Cash interest expense, net of interest income		2.6		2.4
Expansion capital expenditures(4)		12.9		19.2
Maintenance capital expenditures(5)		8.9		10.4
Add:
Available cash and borrowings to fund expansion capital expenditures		12.9		19.2

Pro Forma Available Cash	$	68.2	$	70.8

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)

For the twelve months ended March 31, 2013 and the year ended December 31, 2012, our total pro forma depreciation expense of $30.3 million and $29.9 million, respectively, includes $2.7 million and $2.8 million, respectively, 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 and the twelve months ended March 31, 2013, our total capital expenditures were $29.6 million and $21.8 million, respectively. 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 and $12.9 million of these capital expenditures were expansion capital expenditures for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. 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 and the twelve months ended March 31, 2013, our total capital expenditures were $29.6 million and $21.8 million, respectively. 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 and $8.9 million of these capital expenditures were maintenance capital expenditures for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. 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 $65.4 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.

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.

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	$	118.7
Condensate sales		7.5

Total revenues	$	126.2

Operating expenses
Gathering expense	$	22.8
General and administrative(1)		16.3
Taxes other than income taxes		1.9
Depreciation and amortization		32.0

Total operating expenses		73.0

Operating income		53.2

Income from unconsolidated affiliate(2)		2.8
Interest expense(3)		(2.8	)

Net income	$	53.2

Net income attributable to noncontrolling interest		(3.3	)

Net income attributable to us	$	49.9

Plus:
Depreciation and amortization expense, net of noncontrolling interest portion(4)		29.2
Interest expense		2.8

Adjusted EBITDA(5)	$	81.9

Less:
Cash interest expense, net of interest income(6)		1.7
Expansion capital expenditures(7)		5.8
Maintenance capital expenditures(8)		14.8
Add:
Available cash and borrowings to fund expansion capital expenditure		5.8

Estimated cash available for distribution	$	65.4

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.”

(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 revenues. We expect that production from QEP in the Pinedale Field will continue to provide a significant portion of our total throughput volumes and revenues going forward. 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 production from 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 and 306.9 million MMBtu for the twelve months ended March 31, 2013. 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 and the twelve months ended March 31, 2013 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.

•

Certain of our gathering systems are the subject of ongoing litigation between Questar and QEP Field Services. The dispute relates to the inclusion of certain costs and the methodology used in determining the annual gathering rate charged under a 1993 gathering agreement (1993 Agreement). The gathering rate is calculated on a cost-of-service basis, which takes into account the recovery of capital invested in the gathering system assets, including an allowed return on invested capital, plus recovery of specified operating and overhead costs. The cost of service is divided by annual system throughput to determine a rate per unit of throughput. The rate is redetermined annually based on the prior year’s actual results. Approximately 60% of the revenues associated with the 1993 Agreement are not dependent on throughput volumes, while the remaining 40% are dependent on throughput volumes. In April 2012, Questar began paying QEP Field Services a reduced fee and began posting a security bond for the disputed amount. For purposes of calculating the unaudited pro forma cash available for distribution for the year ended December 31, 2012, approximately $1.3 million of revenue was included for the first quarter of 2012. Due to the uncertainty of the outcome of litigation, the forecast for the twelve month period ended June 30, 2014, excludes the disputed fee amount of approximately $4.3 million. 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 $126.2 million, as compared to $127.5 million for the pro forma year ended December 31, 2012 and $125.5 million for the twelve months ended March 31, 2013. 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 pro forma year ended December 31, 2012 and 306.9 million MMBtu for the twelve months ended March 31, 2013. 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 pro forma year ended December 31, 2012 and 22.5 million MMBtu for the twelve months ended March 31, 2013. The expected change in natural gas throughput for the twelve months ending June 30, 2014 is primarily due to a third-party shipper disruption caused by a fire at one of the shipper’s compressor stations, which occurred late in the fourth quarter of 2012. Our forecast assumes that the shipper will not resume delivery of their full pre-incident volumes to our system during the forecast period.

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 pro forma year ended December 31, 2012 and $0.33 per MMBtu for the twelve months ended March 31, 2013. 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 79% of our total revenues for the pro forma year ended December 31, 2012 and $99.8 million, representing approximately 80% of our total revenues, for the twelve

months ended March 31, 2013. 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 5,056.1 MBbls of crude oil for the twelve months ending June 30, 2014, compared to 5,297.4 MBbls for the pro forma year ended December 31, 2012 and 5,221.0 MBbls for the twelve months ended March 31, 2013. 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 pro forma year ended December 31, 2012 and $2.15 per barrel for the twelve months ended March 31, 2013. The expected decrease in our gathering fees is primarily due to increased contributions from contracts with lower fee structures.

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 and $11.2 million, representing 9% of our total revenues, for the twelve months ended March 31, 2013. 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 $8.5 million, representing 7% of our total revenues for the pro forma year ended December 31, 2012 and $7.2 million, representing 6% of our total revenues, for the twelve months ended March 31, 2013. The expected change in revenue from condensate sales for the twelve months ending June 30, 2014 is primarily due to an expected increase in condensate sales volumes to 88.3 MBbl at an average sales price of $85.18/Bbl, compared to 87.3 MBbl at an average sales price of $82.47/Bbl for the twelve months ended March 31, 2013. The expected decrease in revenue from condensate sales for the twelve months ending June 30, 2014 compared to the year ended December 31, 2012 is primarily due to a contract change wherein a producer customer is now taking its condensate volumes in-kind.

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 and $21.2 million for the twelve months ended March 31, 2013. 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 $16.3 million for the twelve months ending June 30, 2014, compared to pro forma general and administrative expenses of $15.2 million for the pro forma year ended December 31, 2012 and $15.9 million for the twelve months ended March 31, 2013. 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 pro forma year ended December 31, 2012, the twelve months ended March 31, 2013 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 $29.9 million for the pro forma year ended December 31, 2012 and $30.3 million for the twelve months ended March 31, 2013. 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.

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 pro forma year ended December 31, 2012 and $2.4 million for the twelve months ended March 31, 2013. The change in equity income is primarily attributable to the expiration of the minimum volume commitments provided by a transportation contract and a third-party shipper disruption caused by a fire at one of the shipper’s compressor stations, which occurred late in the fourth quarter of 2012. Our forecast assumes that the shipper will not resume delivery of their full pre-incident volumes during the forecast period.

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 pro forma year ended December 31, 2012 and $3.7 million for the twelve months ended March 31, 2013. 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 $2.8 million for the twelve months ending June 30, 2014, compared to pro forma interest expense of $3.5 million for the pro forma year ended December 31, 2012 and $3.6 million for the twelve months ended March 31, 2013. 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 $20.6 million for the twelve months ending June 30, 2014, compared to pro forma capital expenditures of $29.6 million for the pro forma year ended December 31, 2012 and $21.8 million for the twelve months ended March 31, 2013. Our forecast estimate is based on the following assumptions:

Expansion Capital Expenditures. For the pro forma year ended December 31, 2012 and the twelve months ended March 31, 2013, we spent approximately $19.2 million and $12.9 million, respectively, 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. We expect to incur $5.8 million of expansion capital expenditures during the twelve months ending June 30, 2014 with respect to a new compressor and treating plant at Vermillion.

Maintenance Capital Expenditures. Historically, we did not make a distinction between maintenance and expansion capital expenditures. Our estimate that maintenance capital expenditures will be approximately $14.8 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.

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.

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

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;

•

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

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.

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.

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

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.

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
	Quarterly Distribution Per Unit Prior to 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.

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;

•

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.

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

(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

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.

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 QEPM Gathering and Rendezvous Pipeline, (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, 2011 and 2012 are derived from the audited combined financial statements of our Predecessor included elsewhere in this prospectus. The selected historical combined financial and operating data of our Predecessor as of March 31, 2013 and for the three months ended March 31, 2012 and 2013 are derived from the unaudited combined financial statements of our Predecessor included elsewhere in this prospectus.

The selected pro forma combined financial data presented in the following table for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013, respectively, 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 to be effected at the closing of the offering and described under “Prospectus Summary — Formation Transactions and Partnership Structure” had taken place on March 31, 2013, in the case of the pro forma balance sheet, and as of January 1, 2012, in the case of the pro forma statement of operations for the year ended December 31, 2012 and the three months ended March 31, 2013, respectively. These transactions primarily include, and the pro forma financial data give effect to, the following:

•

QEP’s retention of the Uinta Basin Gathering System, its 38% interest in Uintah Basin Field Services and general support equipment, each of 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.”

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,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2011			2012			2012			2013			2012			2013
	(in millions, except per unit amounts)
*Statement of Operations*
Revenues	$	155.9		$	162.2		$	41.9		$	40.1		$	127.5		$	31.0
Operating Expenses:
Gathering expense		27.7			29.9			7.2			7.7			21.1			5.8
General and administrative(1)		15.3			17.0			3.6			5.7			15.2			4.5
Taxes other than income taxes		2.8			3.1			0.8			0.3			2.1			0.2
Depreciation and amortization		38.3			39.8			9.8			10.3			29.9			7.7

Total operating expenses		84.1			89.8			21.4			24.0			68.3			18.2

Loss from asset sales		—			—			—			(0.3	)		—			—

Operating income		71.8			72.4			20.5			15.8			59.2			12.8
Other income		0.1			0.1			—			—			0.1			—
Income from unconsolidated affiliates		4.4			7.2			1.9			1.3			3.5			0.6
Interest expense		(12.8	)		(8.7	)		(1.8	)		(1.1	)		(3.5	)		(0.9	)

Net income		63.5			71.0			20.6			16.0			59.3			12.5
Net income attributable to noncontrolling interest		(3.2	)		(3.7	)		(0.8	)		(0.6	)		(3.7	)		(0.6	)

Net income attributable to Predecessor or us	$	60.3		$	67.3		$	19.8		$	15.4		$	55.6		$	11.9

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					$	625.2					$	493.1
Total assets		714.3			725.4						709.8						558.7
Long-term debt to related party		174.6			131.1						85.7						—
*Statement of Cash flows*
Net cash provided by operating activities	$	97.5		$	107.0		$	36.6		$	38.9
Capital expenditures		(28.6	)		(43.7	)		(11.8	)		(3.9	)
Net cash used in investing activities		(28.5	)		(43.4	)		(11.8	)		(3.1	)
Net cash used in financing activities		(68.0	)		(64.7	)		(24.3	)		(34.3	)


	QEP Midstream Partners, LP Predecessor												QEP Midstream Partners, LP Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2011			2012			2012			2013			2012			2013
	(in millions, except per unit amounts)
*Operating information*
Natural gas throughput in millions of MMBtu
Gathering and transportation		384.7			387.8			93.1			90.6			309.2			72.5
Equity interest(2)		34.4			27.5			7.2			3.3			25.7			2.9

Total natural gas throughput		419.1			415.3			100.3			93.9			334.9			75.4
Throughput attributable to noncontrolling interests(3)		(14.3	)		(12.1	)		(3.4	)		(2.6	)		(12.1	)		(2.6	)

Total throughput attributable to our Predecessor or us		404.8			403.2			96.9			91.3			322.8			72.8

Average gas gathering and transportation fee (per MMBtu)	$	0.30		$	0.34		$	0.35		$	0.36		$	0.32		$	0.34
Crude oil and condensate gathering system throughput volumes (in MBbls)		4,105.4			5,297.4			1,322.4			1,278.8			5,297.4			1,278.8
Average oil and condensate gathering fee (per barrel)	$	1.89		$	2.11		$	1.92		$	2.02		$	2.11		$	2.02
*Non-GAAP Measures*
Adjusted EBITDA(4)	$	109.6		$	112.9		$	30.7		$	26.4		$	86.1		$	19.8

(1)

(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 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
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2011			2012			2012			2013			2012			2013
	(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		$	67.3		$	19.8		$	15.4		$	55.6		$	11.9
Other income		(0.1	)		(0.1	)		—			—			(0.1	)		—
Interest expense		12.8			8.7			1.8			1.1			3.5			0.9
Depreciation and amortization(1)		35.6			37.0			9.1			9.6			27.1			7.0
Deferred revenue associated with minimum volume commitment payments(2)		1.0			—			—			—			—			—
Net loss from asset sales		—			—			—			0.3

Adjusted EBITDA	$	109.6		$	112.9		$	30.7		$	26.4		$	86.1		$	19.8

*Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA*
Net cash provided by operating activities	$	97.5		$	107.0		$	36.6		$	38.9
Noncontrolling interest share of depreciation and amortization		(2.7	)		(2.8	)		(0.7	)		(0.7	)
Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates		(3.3	)		(0.6	)		0.4			(0.2	)
Net income attributable to noncontrolling interest		(3.2	)		(3.7	)		(0.8	)		(0.6	)
Interest expense		12.8			8.7			1.8			1.1
Deferred revenue associated with minimum volume commitment payments(2)		1.0			—			—			—
Other income		(0.1	)		(0.1	)		—			—
Working capital changes		7.6			4.4			(6.6	)		(12.1	)

Adjusted EBITDA	$	109.6		$	112.9		$	30.7		$	26.4

(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, and $0.7 million and $0.7 million during the three months ended March 31, 2013 and 2012, 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 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.

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. As of and for the three months ended March 31, 2013, our gathering systems had 1,475 miles of pipeline and average gross throughput of 1.6 million MMBtu/d of natural gas and 17,414 Bbls/d of crude oil. We believe 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, for the year ended December 31, 2012 and the three months ended March 31, 2013, approximately 7% and 9%, respectively, of our Predecessor revenue was generated 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.

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 52% of our Predecessor’s total revenues and 55% of our total pro forma revenues, respectively, for the three months ended March 31, 2013. 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 primarily affected by upstream development drilling and production volumes from the wells connected to our gathering pipelines. Producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas and NGLs, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

Operating expenses

The primary components of our operating expenses that we evaluate include gathering expense, general and administrative and depreciation and amortization.

Gathering expense. We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, compression costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We will seek to manage our operations and maintenance expenditures on our gathering pipelines by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.

General and administrative. Our Predecessor’s general and administrative expenses included costs allocated by QEP. These costs were reimbursed and relate to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) restructuring, compensation, share-based compensation, and pension and post-retirement costs. General, administrative and management costs were allocated to the Predecessor based on its proportionate share of QEP’s gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies are reasonable. Following the closing of this offering, QEP will continue to charge us a combination of direct and allocated charges for administrative and operational services.

We anticipate incurring approximately $2.5 million of incremental general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual, quarterly reporting and current; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relation expenses and registrar and transfer agent fees; director and officer liability insurance costs and director compensation. These incremental general and administrative expenses are not reflected in our historical or our pro forma combined financial statements. Our future general and administrative expense will also include compensation expense associated with the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan.

Depreciation and amortization. Depreciation and amortization expense consists of our estimate of the decrease in value of the assets capitalized in property, plant and equipment as a result of using the assets throughout the applicable year. Depreciation is recorded on a straight-line basis. We estimate our pipelines, compressors and meters have useful lives ranging from 5 years to 40 years.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income attributable to our Predecessor before depreciation and amortization, interest and other income, interest expense and deferred revenue associated with minimum volume commitment payments. Although we have not quantified distributable cash flow on a historical basis, after the closing of this offering we intend to use distributable cash flow, which we define as Adjusted EBITDA less net cash interest paid and maintenance capital expenditures, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Adjusted EBITDA and distributable cash flow are non-GAAP, supplemental financial measures used 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 is net income attributable to our Predecessor and cash flow from operating activities. Adjusted EBITDA should not be considered an alternative to net income attributable to our Predecessor, 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, and these measures may vary among other companies. As a result, Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For a reconciliation of Adjusted EBITDA to net income attributable to our Predecessor and net cash flows provided by operating activities, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Oil and natural gas supply and demand

Our gathering operations are primarily dependent upon oil and natural gas production from the upstream sector. The decline in natural gas prices has caused a related decrease in natural gas drilling in the United States. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. However, in the areas in which we operate there remains a consistent level of drilling activity due to the liquids content that we believe will offset the production and drilling declines seen in other areas. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in oil and natural gas prices could affect production rates over time and levels of investment by QEP and third parties in exploration for and development of new oil and natural gas reserves. During 2012, QEP operated six drilling rigs in the Pinedale Field, but in 2013 QEP reduced the number of operated rigs to four. Although the rig count is currently lower than 2012, QEP expects to complete approximately the same number of wells for the year ended December 31, 2013 as it did for the year ended December 31, 2012 as a result of more efficient drilling and completion operations. We expect a slight decline in production from the Pinedale Field resulting from the reduced rig count. Please read “Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations.”

Rising operating costs and inflation

The current level of exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

Impact of interest rates

Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs will increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets and may limit our ability to expand our operations or make future acquisitions.

Regulatory compliance

The regulation of oil and natural gas gathering and transportation activities by the Federal Energy Regulatory Commission (FERC), and other federal and state regulatory agencies, including the Department of Transportation, or DOT, has a significant impact on our business. For example, the PHMSA office of the DOT has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation of oil and natural gas. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems. For more information see “Business — Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service.”

Acquisition opportunities

We may acquire additional midstream energy assets from QEP. However, if QEP chooses to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We are not currently a party to any written or unwritten agreements to purchase additional midstream assets from QEP and we do not know when QEP will offer to sell us additional assets, if at all. In addition,

we may pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or QEP’s existing asset base. In addition to our existing areas of operation, we may diversify our business through acquisition and greenfield development opportunities in geographic regions where neither QEP nor we currently operate. We believe that we will be well-positioned to acquire midstream assets from third parties should opportunities arise. If we do not make acquisitions from QEP or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per-unit basis.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations will not be comparable to our Predecessor’s historical results of operations for the reasons described below:

Assets not included in our partnership

Our Predecessor’s results of operations historically included revenues and expenses relating to QEP’s 100% ownership of the Uinta Basin Gathering System, a 38% equity ownership interest in Uintah Basin Field Services and general support equipment. QEP will not contribute the interest in these assets to us in connection with this offering.

General and administrative expenses

We anticipate incurring approximately $2.5 million of incremental general and administrative expenses attributable to operating as 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. These incremental general and administrative expenses are not reflected in our historical or our pro forma combined financial statements. For the year ended December 31, 2012 and the three months ended March 31, 2013, each on a pro forma basis, we incurred $15.2 million and $4.5 million, respectively, in general and administrative expenses.

Working capital

The impact of all affiliated transactions of our Predecessor historically have been net settled within QEP’s combined financial statements because these transactions related to QEP and were funded by QEP’s working capital. Third-party transactions were funded by QEP’s working capital. In the future, all affiliate and third-party transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

Interest expense

Prior to this offering, we incurred interest expense on intercompany notes payable to QEP. These balances will be repaid with a portion of the proceeds from this offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in the future. Upon the closing of this offering, we intend to enter into a $ million revolving credit facility agreement that we expect will incur interest expense at customary short-term interest rates.

Cash distributions to unitholders

At the closing of this offering, we intend to make cash distributions to our unitholders and our general partner at our minimum quarterly distribution of $ per unit per quarter ($ per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from QEP to satisfy our capital expenditure requirements.

Results of Operations

The following table compares the results of our Predecessor’s operations for the years ended December 31, 2012 and 2011 and the three months ended March 31, 2013 and 2012:


	Years Ended December 31,								Three Months Ended March 31,
	2012		2011		$ change		% change		2013		2012		$ change		% change
	(in millions, except operating and per unit amounts)
*Revenues*
Gathering and transportation	$	151.3	$	140.4	$	10.9		8%	$	36.6	$	36.9	$	(0.3)		(1)%
Condensate sales		10.9		15.5		(4.6)		(30)%		3.5		5.0		(1.5)		(30)%

Total revenues		162.2		155.9		6.3		4%		40.1		41.9		(1.8)		(4)%

*Operating expenses*
Gathering expense		29.9		27.7		2.2		8%		7.7		7.2		0.5		7%
General and administrative		17.0		15.3		1.7		11%		5.7		3.6		2.1		58%
Taxes other than income taxes		3.1		2.8		0.3		11%		0.3		0.8		(0.5)		(63%)
Depreciation and amortization		39.8		38.3		1.5		4%		10.3		9.8		0.5		5%

Total operating expenses		89.8		84.1		5.7		7%		24.0		21.4		2.6		12%

Net loss from property sales		—		—		—		—		(0.3)		—		(0.3)		(100)%

Operating income		72.4		71.8		0.6		1%		15.8		20.5		(4.7)		(23)%
Other income		0.1		0.1		—		—%		—		—		—		—%
Income from unconsolidated affiliates		7.2		4.4		2.8		64%		1.3		1.9		(0.6)		(32)%
Interest expense		(8.7)		(12.8)		4.1		(32)%		(1.1)		(1.8)		0.7		(39)%

Net income		71.0		63.5		7.5		12%		16.0		20.6		(4.6)		(22)%
Net income attributable to noncontrolling interest		(3.7)		(3.2)		(0.5)		16%		(0.6)		(0.8)		0.2		(25)%

Net income attributable to Predecessor	$	67.3	$	60.3	$	7.0		12%	$	15.4	$	19.8	$	(4.4)		(22)%

*Operating Statistics*
Natural gas throughput in millions of MMBtu
Gathering and transportation		387.8		384.7		3.1		1%		90.6		93.1		(2.5)		(3)%
Equity interest(1)		27.5		34.4		(6.9)		(20)%		3.3		7.2		(3.9)		(54)%

Total natural gas throughput		415.3		419.1		(3.8)		(1)%		93.9		100.3		(6.4)		(6)%
Throughput attributable to noncontrolling interests(2)		(12.1)		(14.3)		2.2		(15)%		(2.6)		(3.4)		0.8		(24)%

Total throughput attributable to our Predecessor		403.2		404.8		(1.6)		—		91.3		96.9		(5.6)		(6)%

Crude oil and condensate gathering system throughput volumes (in MBbls)		5,297.4		4,105.4		1,192.0		29%		1,278.8		1,322.4		(43.6)		(3)%
Water gathering volumes (in MBbls)		3,998.4		3,536.6		461.8		13%		870.1		907.6		(37.5)		(4)%
Condensate sales volumes (in MBbls)		125.8		177.4		(51.6)		(29)%		42.7		55.1		(12.4)		(23)%
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.34	$	0.30	$	0.04		13%	$	0.36	$	0.35	$	0.01		3%
Average oil and condensate gathering fee (per barrel)	$	2.11	$	1.89	$	0.22		12%	$	2.02	$	1.92	$	0.10		5%
Average water gathering fee (per barrel)	$	1.84	$	1.86	$	(0.02)		(1)%	$	1.80	$	1.81	($	0.01)		(1)%
Average condensate sale price (per barrel)	$	86.06	$	87.21	$	(1.15)		(1)%	$	82.99	$	91.02	($	8.03)		(9)%
*Non-GAAP Measures*
Adjusted EBITDA(3)	$	112.9	$	109.6	$	3.3		3%	$	26.4	$	30.7	$	(4.3)		(14)%

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

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

(3)

For a discussion of Adjusted EBITDA, please read “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.” For a reconciliation of Adjusted EBITDA to net income attributable to our Predecessor and net cash flows provided by operating activities, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Three Months Ended March 31, 2013 compared to Three Months Ended March 31, 2012

Revenue, Volume and Price Variance Analysis

Gathering and transportation. Revenues decreased $0.3 million, or 1%, in the first quarter of 2013 due to a decrease in natural gas gathering revenues. Natural gas gathering revenues were $0.3 million lower in the first quarter of 2013 due to a 2.5 million MMBtu decrease in gathering volumes, partially offset by a 3% increase in the average gathering rate. Natural gas gathering volumes were lower due to a 3.4 million MMBtu decline in Rendezvous Gas Services system throughput from lower delivered volumes, and a 0.3 million MMBtu decline in Vermillion system throughput from a decline in upstream drilling activity, partially offset by a 1.4 million MMBtu increase in Green River system throughput due to an increase in QEP’s Pinedale production. The increase in the average gathering rate was due to a $0.1 million increase in transportation revenues.

Condensate sales. Revenues decreased $1.5 million, or 30%, due to a 23% decrease in volumes and a 9% decrease in price. Condensate sales volumes decreased 62% and 7% on our Green River and Vermillion gathering systems, respectively. The decrease in our Green River system was due to a new contract with QEP that allows QEP to retain its proportionate share of condensate volumes, while the decrease in our Vermillion gathering system was due to lower natural gas gathering volumes. The decrease in the price per barrel in the first quarter 2013 was primarily related to a decrease in the NYMEX crude oil price and additional lower quality condensate which is priced at a discount.

Operating Expenses

Gathering expense. Expenses increased $0.5 million, or 7%, in the first quarter of 2013 primarily due to an increase in labor and benefits costs. Labor and benefits increased due to additional compensation costs from QEP’s annual incentive program.

General and administrative. Expenses increased $2.1 million, or 58%, in the first quarter of 2013 due to increases in headcount and additional compensation costs from QEP’s annual incentive program and the related allocation of direct and indirect costs to the Predecessor.

Taxes other than income taxes. Expenses decreased $0.5 million, or 63%, in the first quarter of 2013 primarily due to a property tax refund related to our Vermillion Gathering System.

Depreciation and amortization. Expenses increased $0.5 million, or 5%, in the first quarter of 2013 primarily due to increases at our Vermillion, Green River and Williston gathering systems of $0.1 million $0.2 million and $0.2 million, respectively. The increase in the Vermillion Gathering System is due to a stabilizer placed into service during the last half of 2012. The increases in the Green River and Williston gathering systems primarily relate to additional gathering equipment placed into service during the last quarter of 2012.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates decreased $0.6 million, or 32%, in the first quarter of 2013 due to a $0.6 million decrease in our Predecessor share of the Three Rivers Gathering partnership net income due to a decrease in the partnership’s natural gas gathering volumes from a third-party shipper disruption caused by a fire at one of the shipper’s compressor stations.

Interest expense. Interest expense decreased $0.7 million, or 39%, in the first quarter of 2013 due to a decrease in outstanding average debt balances with QEP in the first quarter 2013. Average debt outstanding in the first quarter of 2013 was $108.4 million compared to $167.1 million in the first quarter 2012.

Year Ended December 31, 2012 compared to Year Ended December 31, 2011

Revenue, Volume and Price Variance Analysis

Gathering and transportation. Revenues increased $10.9 million, or 8%, in 2012 due to a $6.7 million increase in natural gas gathering revenues, a $3.4 million increase in crude oil and condensate

gathering revenues, and a $0.8 million increase in water gathering revenues. Natural gas gathering revenues were higher in 2012 due to a 13% increase in average gathering fees per MMBtu, and a 3.1 million MMBtu increase in gathering volumes. The increase in the average gathering fee was due to a $1.2 million increase in compression revenues, and a $0.8 million increase in transportation revenues. Natural gas gathering volumes increased primarily due to a 14.6 million MMBtu increase in Green River System throughput related to QEP Pinedale drilling and a 2.7 million MMBtu increase in Vermillion System throughput from increased drilling activity. These throughput increases were offset by a 4.5 million MMBtu decrease in the Uinta Basin Gathering System throughput due to a decline of drilling activity in the area.

Crude oil and condensate gathering revenues increased in 2012 due to a 29% increase in throughput volumes and a 12% increase in the average gathering fee. Oil and condensate gathering volumes increased 620.1 MBbls on our Williston Gathering System from increased drilling by QEP and 571.9 MBbls on our Green River System due to additional unaffiliated volumes. The increase in the average gathering fee was due to an increase of barrels into the system in which we receive a higher fee for transportation of those barrels.

Water gathering revenues increased due to an increase in volumes on our Green River System. The increase in volumes related to QEP’s increased Pinedale drilling operations.

Condensate sales. Revenues decreased $4.6 million, or 30%, due to a decrease in volumes. Condensate sales volumes decreased on our Green River and Uinta Basin gathering systems. The decrease in condensate volumes on our Green River System was due to a new contract with QEP that allows QEP to retain its proportionate share of condensate volumes, while the Uinta Basin Gathering System decrease was due to a decrease in natural gas gathering throughput volumes.

Operating Expenses

Gathering expense. Expenses increased $2.2 million, or 8%, in 2012 primarily due to an increase in labor and benefits costs. Labor and benefits increased due to additional compensation costs from QEP’s annual incentive program.

General and administrative. Expenses increased $1.7 million, or 11%, in 2012 due to increases in headcount and related compensation costs and the related allocation of direct and indirect costs to the Predecessor.

Taxes other than income taxes. Expenses increased $0.3 million, or 11%, in 2012 primarily due to an increase in property taxes related to our Vermillion and Williston gathering systems.

Depreciation and amortization. Expenses increased $1.5 million, or 4%, in 2012 primarily due to increases at our Vermillion, Uinta Basin and Williston gathering systems of $0.6 million, $0.3 million and $0.4 million, respectively. The increase in the Vermillion Gathering System is due to compressors placed into service during the first quarter of 2012. The increases in the Williston and Uinta gathering systems primarily relate to additional gathering equipment placed into service during the first three quarters of 2012.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased $2.8 million, or 64%, in 2012 due to a $1.2 million increase in our Predecessor share of the Uintah Basin Field Services partnership net income and a $1.6 million increase in our Predecessor share of the Three Rivers Gathering partnership net income due to the recognition of deficiency charges in 2012.

Interest expense. Interest expense decreased $4.1 million, or 32%, in 2012 due to a decrease in outstanding average debt balances with QEP in 2012. Average debt outstanding in 2012 was $152.9 million compared to $206.4 million in 2011.

Liquidity and Capital Resources

Historically, our sources of liquidity included cash generated from operations and funding from QEP. We historically participated in QEP’s centralized cash management program for all periods presented,

under which the net balance of our cash receipts and cash disbursements was settled with QEP on a periodic basis. Prospectively, we will maintain our own bank accounts and sources of liquidity and will utilize QEP’s cash management system and expertise.

We expect our ongoing sources of liquidity following this offering to include cash generated from operations, borrowings under our new revolving credit facility, and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Cash Flow

The following table and discussion presents a summary of our Predecessor’s combined net cash provided by operating activities, investing activities and financing activities for the periods indicated.


	Year Ended December 31,												Three Months Ended March 31,
	2012			2011			$ change			% change			2013			2012			$ change			% change
	(in millions)
Net cash provided by (used in):
Operating Activities	$	107.0		$	97.5		$	9.5			10	%	$	38.9		$	36.6		$	2.3			6	%
Investing Activities		(43.4	)		(28.5	)		(14.9	)		52	%		(3.1	)		(11.8	)		8.7			(74	)%
Financing Activities		(64.7	)		(68.0	)		3.3			(5	)%		(34.3	)		(24.3	)		(10.0	)		41	%

Three Months Ended March 31, 2013 compared to Three Months Ended March 31, 2012

Operating Activities

The primary components of net cash provided from operating activities are presented in the following table:


	Three Months Ended March 31,
	2013		2012		$ change			% change
	(in millions)
Net income	$	16.0	$	20.6	$	(4.6	)		(22	)%
Non-cash adjustments to net income		10.8		9.4		1.4			15	%
Changes in operating assets and liabilities		12.1		6.6		5.5			83	%

Net cash provided from operating activities	$	38.9	$	36.6		2.3			6	%

Our Predecessor’s operating cash flows are primarily affected by changes in working capital and non-cash adjustments to net income. Net cash provided from operating activities increased $2.3 million in the first quarter of 2013 due to increases in changes in operating assets and liabilities and non-cash adjustments to net income partially offset by a decrease in net income.

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Investing Activities

Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. Our total historical capital expenditures were as follows:


	Three Months Ended March 31,
	2013		2012
	(in millions)
Total accrual capital expenditures	$	2.2	$	10.8
Change in accruals and non-cash items		1.7		1.0

Total cash capital expenditures	$	3.9	$	11.8

Our Predecessor’s historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. Our Predecessor’s capital investment decreased $7.9 million, to $3.9 million in the first quarter of 2013, compared to $11.8 million in the first quarter of 2012, due primarily to 2012 capital expenditures on the Williston Gathering System for gathering equipment expenditures.

Financing Activities

Our Predecessor’s cash used in financing activities in the first quarter of 2013 primarily consisted of $45.3 million in repayments of long-term debt to QEP compared to $15.1 million in the first quarter of 2012. In addition, our Predecessor had contributions from QEP of $12.5 million and distributions to its noncontrolling interest in Rendezvous Gas of $1.5 million in the first quarter of 2013.

Year Ended December 31, 2012 compared to Year Ended December 31, 2011

Operating Activities

The primary components of net cash provided from operating activities are presented in the following table:


	Year Ended December 31,
	2012			2011			$ change
	(in millions)
Net income	$	71.0		$	63.5		$	7.5
Non-cash adjustments to net income		40.4			41.6			(1.2	)
Changes in operating assets and liabilities		(4.4	)		(7.6	)		3.2

Net cash provided from operating activities	$	107.0		$	97.5		$	9.5

Our Predecessor’s operating cash flows are primarily affected by changes in working capital and net income. Net cash provided from operating activities increased $9.5 million in 2012 due to an increase in changes in operating assets and liabilities and an increase in net income.

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Investing Activities

Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. Our total historical capital expenditures were as follows:


	Year Ended December 31,
	2012		2011
	(in millions)
Total accrual capital expenditures	$	42.4	$	27.1
Change in accruals and non-cash items		1.3		1.5

Total cash capital expenditures	$	43.7	$	28.6

Our Predecessor’s historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. Our Predecessor’s capital investment increased $15.1 million, to $43.7 million in 2012, compared to $28.6 million in 2011, due primarily to increased capital expenditures in Uinta Basin Gathering System for compressor and gathering equipment expenditures. The Uinta Basin Gathering System will be retained by our Predecessor.

Financing Activities

Our Predecessor cash used in financing activities in 2012 primarily consisted of $43.6 million in repayments of long-term debt to QEP compared to $63.6 million in 2011. In addition, our Predecessor had distributions to QEP of $14.5 million and to its noncontrolling interest in Rendezvous Gas of $6.6 million in 2012.

Capital Requirements

The crude oil and natural gas gathering segment of the midstream energy business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement will require that we categorize our capital expenditures as either:

•

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 and to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations; or

•

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.

Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. We expect our Predecessor’s capital expenditures for the year ending December 31, 2013 to be $59.2 million, of which $36.6 million relates to the Uinta Gathering System and the remaining

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$22.6 million relates to QEP Midstream Partners, LP, of which $16.7 million relates to maintenance capital expenditures and the remaining $5.9 million for expansion capital. Of the $16.7 million maintenance capital, we expect to incur $8.0 million for new well connections, $2.0 million for compressor projects, $3.1 million for gathering system projects, and the remaining $3.6 million for various other projects. The expansion capital of $5.9 million provides $4.6 million for compressor replacement projects and $1.3 million for a gas treatment facility. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our credit facility, the issuance of additional partnership units or debt offerings.

Distributions

We intend to pay a minimum quarterly distribution of $ per unit per quarter, which equates to $ million per quarter, or $ million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after completion of this offering. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Credit Facility

Upon the closing of this offering, we intend to enter into a $ million revolving credit facility agreement. At the closing of this offering, we expect to have $ million of borrowing capacity under this facility and it will be available to fund working capital needs, capital expenditures and finance acquisitions. The credit facility is expected to provide for borrowings at short-term interest rates and is expected to contain customary covenants and restrictions. We expect that certain of these covenants, among other things, may limit our ability to make cash distributions, incur indebtedness, create liens, make investments and enter into a merger or sale of substantially all of our assets. We also expect that any unused portion of the credit facility will be subject to a commitment fee.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include individuals and commercial and industrial enterprises that may react differently to changing conditions. Our Predecessor’s principal customer for its crude oil and natural gas gathering services is QEP. We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including QEP. Consequently, we are subject to the risk of non-payment or late payment by QEP of gathering fees, and this risk is greater than it would be with a broader customer base with a similar credit profile. We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on QEP for our revenues. If QEP becomes unable to perform under the terms of our gathering agreements, or the omnibus agreement, it may significantly reduce our ability to make distributions to our unitholders. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

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Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, we enter into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2012:


	Payments Due by Year
	Total		2013		2014		2015		2016		2017		After 2017
	(in millions)
Affiliated debt(1)	$	131.1	$	—	$	—	$	—	$	—	$	131.1	$	—
Asset retirement obligations(2)		16.3		—		—		—		—		—		16.3
Operating leases(3)		7.2		0.6		0.6		0.7		0.7		0.7		3.9

Total	$	154.6	$	0.6	$	0.6	$	0.7	$	0.7	$	131.8	$	20.2

(1)	Affiliated debt reflects the maturity date of our Predecessor’s promissory note which has a maturity date of March 2017.

(2)	These future obligations are discounted estimates of future expenditures based on expected settlement dates.

(3)	These leases represent the portion of QEP’s office space rent that have been allocated to the Predecessor.

Critical Accounting Policies and Estimates

The following discussion relates to the critical accounting policies and estimates for both QEP Midstream Partners, LP and our Predecessor. Our consolidated financial statements are prepared in accordance with U.S. Generally Accepted Accounting Principles. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.

Revenue Recognition

The Predecessor provides natural gas gathering and transportation services, primarily under fee-based contracts. Under these arrangements, the Predecessor receives a fee or fees for one or more of the following services: firm and interruptible gathering or transmission of natural gas, crude oil, condensate, and water. The revenue the Predecessor earns from these arrangements is generally directly related to the volume of natural gas, crude oil, or water that flows through the Predecessor’s systems and is not directly dependent on commodity prices. Revenue for these agreements is recognized at the time the service is performed. In certain of these contracts, the Predecessor’s agreement provides for minimum annual payments or fixed demand charges, which are recognized as revenue pursuant to the contract terms. In addition, under certain of these gathering agreements, the Predecessor retains and sells condensate, which falls out of the natural gas stream during the gathering process. The Predecessor recognizes revenue from condensate sales upon transfer of title. The Predecessor has deferred revenue of which a portion will be recognized as revenue pursuant to contractual terms with the remaining being recognized based on the outcome of certain litigation.

Property, Plant and Equipment

Property, plant and equipment primarily consists of natural gas and oil gathering pipelines, transmission pipelines and compressors and are stated at the lower of historical cost, less accumulated depreciation or fair value, if impaired. The Predecessor capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred, except substantial compression overhaul costs that are capitalized and depreciated. Depreciation of gathering equipment is charged to expense using the straight-line method.

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Capitalization and Depreciation of Assets

Our assets consist primarily of natural gas and oil gathering pipelines, transmission pipelines and compressors. We capitalize construction related direct labor and material costs. Assets placed into service are depreciated, on a straight-line-basis, over the estimated useful life of the asset.

Impairment of Long-lived Assets

Our Predecessor evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset.

Asset Retirement Obligations

Asset retirement obligations (ARO) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at our Predecessor’s credit-adjusted, risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Environmental Obligations

Management makes judgments and estimates in accordance with applicable accounting rules when it establishes reserves for environmental remediation, litigation and other contingent matters. Provisions for such matters are charged to expense when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. Estimates of environmental liabilities are based on a variety of matters, including, but not limited to, the stage of investigation, the stage of the remedial design, evaluation of existing remediation technologies, and presently enacted laws and regulations. In future periods, a number of factors could significantly change our estimate of environmental remediation costs, such as changes in laws and regulations, changes in the interpretation or administration of laws and regulations, revisions to the remedial design, unanticipated construction problems, identification of additional areas or volumes of contaminated soil and groundwater, and changes in costs of labor, equipment and technology. Consequently, it is not possible for management to reliably estimate the amount and timing of all future expenditures related to environmental matters and actual costs may vary significantly.

Recent Accounting Developments

In December of 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. The amendments are required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The adoption of this ASU is not expected to have a material effect on its disclosure requirements.

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Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

At March 31, 2013, our Predecessor had a promissory note with our affiliate, QEP, with a fixed rate of 6.05%, that is not subject to interest rate movements. We anticipate that our new credit facility will contain a variable interest rate that exposes us to volatility in interest rates. However, at the closing of this offering, we do not expect to borrow any funds under our new credit facility.

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenues are dependent upon the price received for the condensate. Condensate historically sells at a price representing a slight discount to the price of crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of revenues generated under these arrangements compared to our overall revenues. Historically, we have not entered into commodity derivative instruments because of the minimal impact on our revenues, however, we expect to have agreements in place with QEP with primary terms of five years to sell condensate volumes on our Green River and Vermillion gathering systems at a fixed price. In addition, we expect to utilize risk management tools to minimize future commodity price risk that could be associated with assets we may acquire or contracts we may enter into in the future.

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INDUSTRY OVERVIEW

General

We provide gathering, compression and transportation services to producers and users of natural gas and crude oil. The market we serve, which begins at the point of purchase at the source of production and extends to the point of distribution to the end-user customer, is commonly referred to as the “midstream” market.

The midstream natural gas industry is the link between the exploration and production of natural gas from the wellhead or lease and the delivery of the natural gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and natural gas liquids, or NGLs, and then routing the separated dry gas and NGL streams for delivery to end-markets or to the next intermediate stage of the value chain.

The diagram below depicts the segments of the natural gas value chain:

LOGO

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Refined petroleum products, such as jet fuel, gasoline and distillate fuel oil, are all sources of energy derived from crude oil. According to 2011 data compiled by the EIA, petroleum currently accounts for about 36% of the nation’s total annual energy consumption. The diagram below depicts the segments of the crude oil value chain:

LOGO

Natural Gas Midstream Services

The range of services utilized by midstream natural gas service providers are generally divided into the following seven categories:

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression. Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration. Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing. The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to

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remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation. The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. This mixture is often referred to as y-grade or raw make NGL. Fractionation is the process by which this mixture is separated into the NGL components prior to their sale to various petrochemical and industrial end users.

Natural Gas Transmission. Once the raw natural gas has been treated and processed, the remaining natural gas, or residue natural gas, is transported to end users. The transmission of natural gas involves the movement of pipeline-quality natural gas from gathering systems and processing facilities to wholesalers and end users, including industrial plants and LDCs. LDCs purchase natural gas on interstate and intrastate pipelines and market that natural gas to commercial, industrial and residential end users. Transmission pipelines generally span considerable distances and consist of large-diameter pipelines that operate at higher pressures than gathering pipelines to facilitate the transportation of greater quantities of natural gas. The concentration of natural gas production in a few regions of the U.S. generally requires transmission pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

NGL Products Transportation. Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts.

Crude Oil Gathering and Transportation

Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the United States. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Common carrier pipelines have published tariffs that are regulated by FERC or state authorities. Pipelines may also be proprietary or leased entirely to a single customer. Crude oil gathering assets generally consist of a network of smaller diameter pipelines that are connected directly to the well site or central receipt points delivering into larger diameter trunk lines. Logistic hubs like Cushing, OK provide storage and connections to other pipeline systems and modes of transportation, such as tankers, railroads and trucks. Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation.

Barges and railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users. Barge transportation is typically a cost-efficient mode of transportation that allows for the ability to transport large volumes of crude oil over long distances.

Competition in the crude oil gathering industry is typically regional and based on proximity to crude oil producers, as well as access to attractive delivery points. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area.

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Contractual Arrangements

Midstream natural gas and crude oil services are usually provided under contractual arrangements with varying amounts of commodity price risk. Several common types of natural gas and crude oil services contracts, including some common “level of service” and various dedication provisions, are described below.

Gathering Contracts

Fee-Based. Under fee-based, natural gas arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead. Similarly, under fee-based, crude oil arrangements, the service provider typically receives a fee tied to an applicable volumetric throughput tariff rate for each unit of crude oil gathered. The services performed by the service provider typically include crude oil treating and stabilization at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Processing Contracts

Fee-Based. Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure.

Percent-of-Proceeds. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate of the processing plant. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs.

Keep-Whole. Under these arrangements, the service provider keeps 100% of the NGLs produced, while the processed natural gas, or value of the natural gas, is returned to the producer. Since some of the natural gas is used and removed during processing, the processor compensates the producer for the amount of natural gas used and removed in processing by supplying additional natural gas or by paying an agreed-upon value for the natural gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.

Common Contractual Provisions

Level of Service Provision

There are two levels of service provisions commonly used in gathering, transportation, and processing contracts across the midstream sector; firm and interruptible service. Each level of service governs the availability of capacity on the service provider’s system for a specific customer and the priority of movement of a specific customer’s products relative to other customers, especially in the event that total customer demand for services exceeds available system capacity.

Firm Service. Firm service requires the reservation of system capacity by a customer between certain receipt and delivery points or processing capacity by a customer at a specific processing facility. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage or throughput fee based on the amount of natural gas or crude oil actually gathered, transported, or, in the case of natural case, processed. In exchange for such fees, which are generally higher than rates charged for other levels of service and subject to other provisions of the gathering, transportation, or processing agreements, as applicable, firm service customers enjoy the first right to available capacity on the system or at the processing facility, as applicable, up to the reserved amount. Firm service is usually contracted by customers who need a high degree of certainty that their product will always move on the system or at a processing facility, as applicable, even in times when total volumes available exceed system capacity.

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Interruptible Service. Interruptible service is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of natural gas or crude oil actually gathered, transported, or, in the case of natural gas, processed. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the processing facility.

Dedication Provisions

The midstream contracts referenced above may contain provisions that in the industry are often referred to as “life-of-reserves” or “life-of-lease” dedications. The provisions effectively dedicate any and all production from specified leases or existing and future wells on dedicated lands for as long there is commercial production from such identified wells or leases. These provisions contain dedications that typically remain in effect even if ownership of the subject acreage or well changes in the future.

U.S. Natural Gas Fundamentals

Natural Gas Demand

Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 27% of all energy used in the United States in 2012, representing 25.5 Tcf of natural gas. The EIA estimates that over the next 30 years, total domestic energy consumption will increase by over 10%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2012.

LOGO

Source: EIA, Annual Energy Outlook 2013 (April 2013).

According to the EIA, during the period from 2001 through 2012, natural gas consumption increased by 14.5% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 69.7 Bcf/d in 2012. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation sector, where consumption grew by approximately 71.0%. The growth in this sector was partially offset by an approximate 12.5% decline in natural gas consumption in the residential sector.

Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from

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seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 69.7 Bcf/d in 2012 to 80.8 Bcf/d in 2040.

Natural Gas Supply

Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 36.1% in 2011. According to EIA data, during the five-year period from January 2007 through December 2012, marketed domestic production of natural gas increased by an average of approximately 4.6% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

In 2012, the EIA estimated that the United States held 542 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 50% in 2040 as compared with 34% in 2011.

Natural Gas Production (Tcf) by Source, 1990-2040

Source: EIA, Annual Energy Outlook 2013 (April 2013).

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BUSINESS

Overview

We provide all of our gathering services through fee-based agreements, the majority of which have annual inflation adjustment mechanisms. For the three months ended March 31, 2013, approximately 71% of our revenues were generated pursuant to contracts with remaining terms in excess of seven years, including 56% of our revenues that were generated pursuant to “life-of-reserves” contracts. In addition to our fee-based gathering services, for the three months ended March 31, 2013, approximately 6% of our revenue was generated through the sale of condensate volumes that we collect on our gathering systems. For the three months ended March 31, 2013, approximately 50% of our natural gas gathering volumes and approximately 33% of our crude oil volumes were comprised of production owned by QEP, making QEP our largest customer.

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 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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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.

•

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.

•

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.

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 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.

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•

Acquisition opportunities. After the closing of this offering, QEP will continue to own a substantial 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, and we do not know when, or if, QEP will make any such offer.

•

QEP. QEP is actively operating in the Rocky Mountain region and as of December 31, 2012 served 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.

•

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. 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.

•

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.

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Our Assets and Operations

Our primary assets consist of:

•

a 100% ownership interest in QEPM Gathering, which includes the:

•

Green River Gathering Assets – 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 of Wyoming;

•

Vermillion Gathering System – 454 miles of natural gas gathering pipelines located in the Green River Basin of southern Wyoming and northwest Colorado and the Uinta Basin in eastern Utah; and

•

Williston Gathering System –17 miles of crude oil gathering pipelines and 17 miles of natural gas gathering pipelines located in the Williston Basin of North Dakota;

•

a 78% ownership interest in Rendezvous Gas, a joint venture that owns three parallel, 103-mile high-pressure natural gas gathering pipelines located in the Green River Basin of Wyoming;

•

a 100% ownership interest in Rendezvous Pipeline, which owns a 21-mile, FERC-regulated natural gas transmission pipeline in the Green River Basin of Wyoming; and

•

a 50% ownership interest in Three Rivers Gathering, a joint venture that owns 50 miles of natural gas gathering pipelines located in the Uinta Basin of eastern Utah.

The following sections provide more detail about our four natural gas gathering systems and two FERC-regulated pipelines, and the services they provide to our customers.

Green River System

The Green River System includes the Green River Gathering Assets owned by QEPM Gathering and the assets owned by Rendezvous Gas and Rendezvous Pipeline. The following table and map provide information regarding our Green River System as of March 31, 2013:


Gathering System	Asset Type	Length *(miles)*		Receipt Points		Compression *(horsepower)*		Throughput Capacity *(MMcf/d)* (1)			Average Daily Throughput (Thousand MMBtu/d)(1)
Green River Gathering Assets	Gas Gathering		405		307		41,053		737			527
	Oil Gathering		61		93		—		7,137	(2)		3,205	(2)
	Water Gathering		81		93		—		21,990	(3)		9,668	(3)
	Oil Transmission(4)		60		6		—		40,800	(2)		10,806	(2)
Rendezvous Gas Services(5)	Gas Gathering		309		3		7,800		1,032			564
Rendezvous Pipeline	Gas Transmission(4)		21		1		—		460			269

Total			937		503		48,853

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2013.

(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%.

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Overview. The Green River System, located in western Wyoming, consists of three complimentary assets – the Green River Gathering Assets and the assets owned by Green River Gathering, Rendezvous Gas and Rendezvous Pipeline – and gathers natural gas production from the Pinedale, Jonah and Moxa Arch fields and transports that production to multiple gas processing plants in the region. The system also gathers and stabilizes crude oil production from the Pinedale Field and delivers it to our FERC-regulated crude oil pipeline. In addition, the system includes water gathering and handling facilities to manage the produced and flowback water associated with well completion activities in the Pinedale Field.

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Construction of the majority of the Pinedale Field gas gathering infrastructure began in the late 1990’s in connection with the successful application of multi-stage hydraulic fracturing. We have continued to expand the Green River System as production from the Pinedale Field has grown, with gross system throughput capacity volumes exceeding 700 MMcf/d at March 31, 2013. For the three months ended March 31, 2013, the Green River System had total gross natural gas throughput of 527 thousand MMBtu/d and represented approximately 57% of our total revenues.

Delivery Points. Natural gas gathered on the Green River System is delivered to QEP’s Blacks Fork and Emigrant Trail gas processing facilities as well as the Granger gas processing complex, which is owned by Western Gas via the Rendezvous Gas pipeline system. We believe that QEP’s processing facilities are uniquely positioned because they provide direct access to six interstate gas pipelines: the Rockies Express Pipeline (REX); the Northwest Pipeline (NWPL); the Kern River Gas Transmission Company Pipeline (KRPL) (via Rendezvous Pipeline); the Overthrust Pipeline (OTPL); the Colorado Interstate Gas Pipeline (CIG); and the Questar Pipeline Company Pipeline (QPC). We believe these pipeline interconnects maximize producers’ marketing alternatives by providing our customers access to natural gas markets in the Midwest and Eastern United States via REX and OTPL; the Pacific Northwest via NWPL; southern Utah, Nevada and southern and central California via KRPL; regional markets along the eastern Rocky Mountains via CIG and the Wasatch Front in Utah via QPC and OTPL. In addition, through the QEP-owned Blacks Fork gas processing complex and third-party NGL pipelines, producers have direct access to the Mont Belvieu NGL market.

Crude oil gathered on the Green River System is delivered to the Rocky Mountain Pipeline System (RMPL) at LaBarge, Wyoming. Produced water and flowback water gathered by our water gathering system is delivered to a third-party recycling and reclamation facility, and the recycled water is then delivered back into our system for use by producers in connection with future well completion operations.

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The following diagram provides an overview of the crude oil and natural gas production flows on the Green River System:

Green River System Overview

Supply. The primary source of supply for the Green River System is the Pinedale Field, the largest natural gas field in the Rocky Mountain region and one of the lowest operating cost sources of natural gas supply in the United States. The field is located in the northern portion of the Green River Basin in Sublette County, Wyoming. QEP’s portion of the Pinedale Field is developed primarily on pads, with multiple wells drilled directionally from a single pad resulting in less surface intrusion and more efficient gathering operations. As of March 31, 2013, the Green River System gathered production from 758 gross QEP-operated wells on over 17,000 gross acres located in the Pinedale Field. In addition to the Pinedale Field, the Green River System also gathers natural gas from a portion of the Jonah and the Moxa Arch fields in Sublette and Sweetwater Counties, Wyoming.

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The following sections provide more detail about our Green River Gathering Assets and the services they provide to our customers.

Green River Gathering

Overview. Our Green River Gathering Assets are located in two distinct geographic areas: the Pinedale Field (Pinedale System) and the Moxa Arch fields (Moxa System).

The Pinedale System gathers natural gas production from the Pinedale Field in southwest Wyoming, which is one of the lowest operating cost sources of natural gas supply in the United States. We expect this competitive cost of supply will continue to support QEP’s ongoing field development activity in the region. We believe that the remaining gross total proved reserves from wells that QEP operates on acreage dedicated to the system are approximately 3.6 Tcfe.

The Pinedale System is comprised of approximately 220 miles of natural gas, crude oil and produced/flowback water gathering pipelines and 36,065 brake horsepower (bhp) of gas compression. Natural gas gathered by the Pinedale System, along with gas gathered on a third-party system, is delivered into the Rendezvous Gas system for transportation to gas processing facilities located approximately 100 miles south of the producing area. In addition to field-level gas gathering, the system also includes field-level crude oil gathering and stabilization facilities, water gathering and handling facilities, and a 60-mile, FERC-regulated crude oil pipeline that gathers and transports crude oil from the Pinedale Field area to the Rocky Mountain Pipeline System near LaBarge, Wyoming. The Pinedale System has a current aggregate natural gas throughput capacity of 679 MMcf/d and had average gross natural gas throughput of approximately 497 thousand MMBtu/d for the three months ended March 31, 2013. The Pinedale System also had average gross gathering throughput of 3,205 Bbls/d of oil and 9,668 Bbls/d of water for the three months ended March 31, 2013. Our FERC-regulated, crude oil pipeline, which includes third-party, crude oil volumes not gathered on our system, had average gross throughput of 10,806 Bbls/d for the three months ended March 31, 2013.

The Moxa System gathers liquids-rich natural gas from producing wells that are primarily operated by Questar. The Moxa System is comprised of approximately 323 miles of low-pressure gathering pipelines with 4,988 bhp of gas compression. The Moxa System has aggregate throughput capacity of 58 MMcf/d and had average gross throughput of approximately 30 thousand MMBtu/d for the three months ended March 31, 2013.

Contracts. The Pinedale System and the Moxa System are primarily supported by “life-of-reserves” and long-term, fee-based gathering agreements that include acreage dedications. The Pinedale System and the Moxa System have approximately 17,000 and 185,000 gross dedicated acres, respectively. Approximately 466 thousand MMBtu/d, or 82%, of the natural gas throughput for the three months ended March 31, 2013 was delivered pursuant to a “life-of-reserves” contract.

Customers. Four customers accounted for approximately 94% of the natural gas throughput and approximately 93% of the natural gas gathering revenue on the Pinedale and Moxa systems for the three months ended March 31, 2013. QEP gas production totaled approximately 307 thousand MMBtu/d, or approximately 58%, of the natural gas throughput on the Pinedale and Moxa systems for the three months ended March 31, 2013, making it our largest customer. The remaining natural gas throughput on the Pinedale and Moxa systems consisted of production from several third-party producers, including Ultra, Questar and Anadarko, which represented approximately 20%, 11% and 5%, respectively, of throughput during the three months ended March 31, 2013. Ultra and Chevron are the two largest shippers on our FERC-regulated, crude oil pipeline, representing approximately 3,100 Bbls/d and 2,500 Bbls/d, respectively, or 52% in the aggregate, of the throughput on the pipeline for the three months ended March 31, 2013. The remaining throughput on the system was comprised of production volumes from several other producers, including Shell and Plains All American.

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Rendezvous Gas

Overview. Rendezvous Gas is a joint venture between QEP and Western Gas that was formed to own and operate the infrastructure that transports gas from the Pinedale and Jonah fields to several re-delivery points, including natural gas processing facilities that are owned by QEP or Western Gas. QEP and Western Gas dedicated to Rendezvous Gas the natural gas gathering throughput each party had the contractual right to gather within an area of mutual interest, or AMI, in exchange for jointly constructing a single natural gas gathering system. 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. Average gross throughput on the Rendezvous Gas system was 564 thousand MMBtu/d for the three months ended March 31, 2013.

Contracts. The Rendezvous Gas joint venture was established to provide a contractual structure that is seamless to producers that dedicated natural gas to either QEP or Western Gas within the AMI. Rather than have each producer enter into a separate gathering contract with Rendezvous Gas for gathering services, QEP and Western Gas entered into separate gathering agreements with Rendezvous Gas for each party’s dedicated gas.

Customers. QEP is the largest customer on the Rendezvous Gas system, representing approximately 77% of the total system throughput volumes and approximately 81% of the revenue generated during the three months ended March 31, 2013. The remaining throughput on the system and revenue generated is provided by production from an affiliate of Western Gas.

Rendezvous Pipeline

Overview. 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 269 thousand MMBtu/d for the three months ended March 31, 2013.

Contracts. The capacity on the Rendezvous Pipeline system is contracted under long-term transportation contracts that contain firm throughput commitments. Approximately 54% of the throughput volumes in the first quarter of 2013 were subject to contracts with remaining terms of more than nine years. The Rendezvous Pipeline tariff does not specify a rate because the rates are market-based and negotiated with each individual customer.

Customers. QEP is the largest shipper on the Rendezvous Pipeline system representing approximately 75% of the throughput volumes and approximately 85% of revenue generated during the three months ended March 31, 2013. The remaining throughput on the system was comprised of production from third-party producers, including Ultra and Anadarko, which represented approximately 18% and 9% of throughput during the three months ended March 31, 2013, respectively.

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Vermillion Gathering System

The Vermillion Gathering System includes the assets owned by Vermillion Gathering. The following table and map provide information regarding our Vermillion gathering assets as of March 31, 2013:

Gathering System

Asset Type

Length
(miles)

Receipt
Points

Compression
(horsepower)

Throughput
Capacity
(MMcf/d) (1)

Average Daily
Throughput
(Thousand
MMBtu/d)(1)

Vermillion Gathering System

Gas Gathering

454

503

23,197

206

146

(1)	Represents 100% of the capacity and throughput of the system as of and for the three months ended March 31, 2013.

Overview. The Vermillion gathering assets consist of several small gas gathering systems 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. We refer to these individual gas gathering systems collectively as the Vermillion Gathering System. The largest gathering system included within the overall Vermillion Gathering System is the Hiawatha gathering system, which straddles the Wyoming and Colorado border and is located upstream of the Vermillion processing plant. The Hiawatha gathering system consists of approximately 182 miles of gas gathering pipelines and 9,591 bhp of gas compression. The Vermillion Gathering System has a combined total throughput capacity of 206 MMcf/d and had average gross throughput of 146 thousand MMBtu/d for the three months ended March 31, 2013.

Contracts. The Vermillion Gathering System is primarily supported by “life-of-reserves” and long-term, fee-based gas gathering agreements with minimum volume commitments. Approximately 68% of first quarter of 2013 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. For a discussion regarding our minimum volume commitments, please read “— Minimum Volume Commitments.”

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Customers. For the three months ended March 31, 2013, four customers accounted for approximately 87% of the total natural gas throughput and approximately 86% of the total revenue on the Vermillion Gathering System. Our largest customer on the Vermillion Gathering System is Questar, which accounted for approximately 72 thousand MMBtu/d, or 50%, of the first quarter of 2013 total natural gas throughput and approximately 48% of the first quarter of 2013 total generated revenue. The other primary customers on our Vermillion Gathering System were Samson Resources, QEP and Chevron, which accounted for approximately 19%, 12% and 5% of the total natural gas throughput during the three months ended March 31, 2013, respectively.

Delivery Points. Natural gas gathered on the Hiawatha gathering system is delivered to QEP’s Vermillion processing plant with the residue gas delivered into QPC’s interstate pipeline system. The natural gas gathered on the other gathering systems included in the Vermillion assets is delivered directly to QPC’s interstate pipeline system.

Supply. The Vermillion Gathering System gathers natural gas from fields located in the southern portion of the Green River Basin of southwestern Wyoming and northwestern Colorado and the Uinta Basin of eastern Utah. Major fields gathered by the Hiawatha gathering system include the Canyon Creek, Trail and Hiawatha Fields in the Vermillion sub-basin of Sweetwater County, Wyoming, and Moffat County, Colorado. QEP owns over 138,000 gross acres in the Vermillion sub-basin that are dedicated to our Vermillion Gathering System. The acreage is available for future drilling and QEP is currently awaiting BLM approval of an Environmental Impact Statement (EIS). Other major sources of supply for the Vermillion Gathering System are the Powder Wash Field in Moffat County, Colorado, and the Dripping Rock/Mulligan Draw/Wedge fields in Sweetwater County, Wyoming.

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Three Rivers Gathering System

The Three Rivers Gathering System includes the assets owned by Three Rivers Gathering. The following table and map provides information regarding our Three River Gathering System as of March 31, 2013:

Gathering System

Asset Type

Length
(miles)

Receipt
Points

Compression
(horsepower)

Throughput
Capacity
(MMcf/d) (1)

Average Daily
Throughput
(Thousand
MMBtu/d)(1)

Three Rivers Gathering System(2)

Gas Gathering

4,735

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(1)	Represents 100% of the capacity and throughput of the system as of and for the three months ended March 31, 2013.

(2)	Our ownership interest in Three Rivers Gathering is 50%.

Overview. Three Rivers Gathering is a joint venture between QEP and Ute Energy that was formed to transport natural gas gathered by Uintah Basin Field Services, an indirectly owned subsidiary in which QEP owns a 38% interest, 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 has total throughput capacity of 212 MMcf/d and had average gross throughput of 65 thousand MMBtu/d for the three months ended March 31, 2013.

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Contracts. The Three Rivers Gathering System is primarily supported by long-term, fee-based gas gathering agreements with minimum volume commitments. Approximately 95% of first quarter of 2013 throughput volumes were subject to contracts with remaining terms of more than seven years. The system has aggregate minimum volume commitments of 212 thousand MMBtu/d from three different producers through 2018. The Three Rivers Gathering System is currently fully subscribed with minimum volume commitments, but we believe we can easily expand this system by adding incremental compression or strategically placed looping of the pipeline. For a discussion regarding our minimum volume commitments, please read “— Minimum Volume Commitments.”

Customers. XTO and Bill Barrett are the two largest shippers on the Three Rivers Gathering System, representing approximately 42 thousand MMBtu/d and 7 thousand MMBtu/d, respectively, or approximately 76% in the aggregate, of the throughput on the system for the three months ended March 31, 2013. The remaining throughput on the system was comprised of production from several producers, including QEP, Koch Exploration Company, LLC and Whiting Petroleum Corporation.

Delivery Points. Natural gas gathered on the Three Rivers Gathering System is delivered to either QEP’s Ironhorse / Stage Coach processing complex or to a third-party processing facility. Processed gas is delivered into one of four interstate pipelines: CIG, WIC, QPC or NWPL. Also, through the QEP-owned Stagecoach / Iron Horse gas processing complex and third party NGL pipelines, producers have direct access to the Mont Belvieu NGL market.

Supply. The primary sources of supply for the Three Rivers Gathering System are the Prickly Pear and Peter’s Point fields located in the western portion of the Uinta Basin in Carbon County, Utah and the Flat Rock / Wolf Flat field area along the southern margin of the Uinta Basin in Uintah County, Utah. QEP has 18,860 gross acres of operated leasehold and 10 gross wells in the Flat Rock/Wolf Flat area that are dedicated, in each case, to our Three Rivers Gathering System.

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Williston Gathering System

The Williston Gathering System includes the assets owned by Williston Gathering. The following table and map provide information regarding our Williston Gathering System as of March 31, 2013:


Gathering System	Asset Type	Length *(miles)*		Receipt Points		Compression *(horsepower)*		Throughput Capacity *(MMcf/d)* (1)		Average Daily Throughput (Thousand MMBtu/d)(1)
Williston Gathering System	Gas Gathering		17		24		239		3		1
	Oil Gathering(2)		17		24		—		7,000		3,402

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2013.

(2)	Throughput measured in barrels of crude oil per day.

LOGO

Overview. 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. In addition to the crude oil and natural gas gathering services, we operate a 17-mile water gathering system on a cost of service basis for QEP. The Williston Gathering System has total crude oil throughput capacity of 7,000

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Bbls/d and had average gross throughput of 3,402 Bbls/d of crude oil for the three months ended March 31, 2013. The system has total gas throughput capacity of 3 MMcf/d and had average gross throughput of 3 thousand MMBtu/d of gas for the three months ended March 31, 2013.

Contracts. The Williston Gathering System is primarily supported by long-term, fee-based, crude oil and gas gathering agreements with minimum volume commitments. All of the first quarter of 2013 throughput volumes are subject to contracts with remaining terms of more than ten years. The system has aggregate minimum volume commitments of approximately 5,600 Bbls/d of crude oil and 5 thousand MMBtu/d of natural gas from one producer through 2026. For a discussion regarding our minimum volume commitments, please read “— Minimum Volume Commitments.”

Customers. QEP is the largest customer on the Williston Gathering System, representing approximately 80% of the throughput volumes and approximately 94% of revenue generated for the three months ended March 31, 2013. QEP provided approximately 2,623 Bbls/d of actual throughput during the three months ended March 31, 2013, which was below their minimum volume commitment of 5,600 Bbls/d, and was therefore subject to a deficiency payment. The remaining throughput on the system is production from Marathon Oil Company, which has dedicated approximately 5,000 acres to the system.

Delivery Points. Crude oil on our Williston Gathering System is delivered into the Bridger pipeline system where it connects to the Bridger Stanley station, with further interstate delivery options via truck, rail or pipeline.

Supply. The Williston system gathers crude oil and natural gas from the wells drilled in the Lower Mississippian / Upper Devonian Middle Bakken Formation and the Mississippian Three Forks Formation in the Williston Basin located east of Lake Sakakawea in McLean County, North Dakota. The system gathers production from horizontal wells targeting tight reservoirs in both formations drilled by QEP and other operators. As of the end of the first quarter of 2013, QEP had 21 gross operated producing wells connected to the system, and approximately 38,000 gross acres of operated leasehold on the east side of Lake Sakakawea that can be accessed by the system.

Minimum Volume Commitments

Several of our gathering agreements related to our Vermillion, Three Rivers and Williston gathering systems contain minimum volume commitments, pursuant to which our customers guarantee to ship a minimum volume of natural gas or oil on these gathering systems. The original terms of the minimum volume commitments range from 10 to 28 years. In addition, certain of our customers have an aggregate minimum volume commitments, 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 can operate to reduce or delay the cash flows that we expect to receive from our minimum volume commitments. These provisions include the following:

•

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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 ships volumes in excess of its minimum volume commitments, 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 commitments.

•

Our Relationship with QEP Resources, Inc.

•

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

•

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 actively operating in several 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 9% increase, respectively, in production and proved reserves as compared to the year ended December 31, 2011.

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The following table provides 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)*		Average Daily Throughput (Thousand MMBtu/d)(1)
Uinta Basin Gathering System	Uinta Basin		609		1,946		54,306		299		201
Uintah Basin Field Services(2)	Uinta Basin		78		21		5,360		26		11
Haynesville Gathering System	Haynesville Shale		200		230		7,360		2,000		228

Total			887		2,197		67,026		2,325		440

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2013.

(2)	QEP’s ownership 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)

Blacks Fork Processing Complex

Green River Basin

Processing

Cryogenic /

Joule-Thomson

835

464

Fractionation

Fractionator

15,000

(2)(3)

2,671

(2)

Emigrant Trail Processing Plant

Green River Basin

Processing

Cryogenic

Vermillion Processing Plant(4)

Southern Green River Basin

Processing

Cryogenic

Uinta Basin Processing Complex

Uinta Basin

Processing

Cryogenic /

Refrigeration

650

(5)

283

Haynesville Gathering System

Haynesville Shale

Treating

600

228

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 three months ended March 31, 2013.

(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 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.

As the owner of (i) our general partner interest, (ii) all of our incentive distribution rights, and (iii) a % limited partner interest in us, we believe that QEP is motivated to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business. However, QEP is under no obligation to make acquisition opportunities available to

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us, is not restricted from competing with us and may acquire, construct or dispose of midstream assets without any obligation to offer us the opportunity to purchase or construct these assets. Please read “Certain Relationships and Related Transactions — Agreements Governing the Transactions — Omnibus Agreement” for additional information.

We will enter into an omnibus agreement with QEP in connection with this offering. The omnibus agreement will address our payment of fees 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. 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.” 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.

Competition

The oil and natural gas gathering business is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for oil and natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to markets, location, available capacity, capital expenditures and fuel efficiencies. Our principal competitors are Enterprise Products Partners, L.P., Western Gas and The Williams Companies, Inc.

In addition to competing for oil and natural gas volumes, we face competition for customer markets, which is primarily based on the proximity of pipelines to the markets, price and assurance of supply.

As a result of our contractual relationship with QEP under our gathering agreements, we believe that our gathering systems and other midstream assets will not face significant competition from other pipelines for QEP’s crude oil, natural gas or products transportation requirements.

Seasonality

Our operations, most notably in the Pinedale Field, are affected by seasonal weather conditions. From approximately December through March of each year, QEP typically ceases completion services on all newly drilled wells in the Pinedale Field due to adverse weather conditions. As a result, we will not add throughput on our Green River System during this period, and existing levels of throughput may decline as the wells connected to our Green River System experience natural production declines. We expect the impact of such seasonality to diminish as we expand our existing assets or acquire additional assets outside of the Pinedale Field.

Insurance

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We will be insured under QEP’s corporate property and liability insurance policies and be subject to the shared deductibles and limits under those policies. We will also maintain our own property, business interruption and pollution liability insurance policies separately from QEP and at varying levels of deductibles and limits that we believe are

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reasonable and prudent under the circumstances to cover our operations and assets. As we continue to grow, we will continue to evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

Safety and Maintenance

Some of our natural gas pipelines are subject to regulation by the PHMSA pursuant to the NGPSA, and the PSIA, as reauthorized and amended by the PIPES Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (HCAs). Our crude oil pipeline and certain of our crude gathering lines are subject to regulation by PHMSA under the HLPSA, which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and the PSA, added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the APSA, which limited the operator identification requirement to operators of pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

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perform ongoing assessments of pipeline integrity;

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identify and characterize applicable threats to pipeline segments that could impact a HCA;

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improve data collection, integration and analysis;

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repair and remediate pipelines as necessary; and

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implement preventive and mitigating actions.

Although many of our pipeline facilities fall within a class that is currently not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our Rendezvous Pipeline assets and our Green River and Williston gathering systems. 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. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

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The 2011 Pipeline Safety Act reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. 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 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. The PHMSA recently issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule change does not affect our current pipelines. Future liquid pipeline expansions may be subject to this rule, but we do not believe compliance with the rule will have a material effect on our operations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks,

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caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

We and the entities in which we own an interest are also subject to:

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EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials;

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OSHA Process Safety Management Regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive materials; and

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Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities.

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

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.

Our natural gas gathering and crude gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas or crude oil without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas or crude oil. States in which we operate have adopted a complaint-based regulation of natural gas or crude oil gathering activities, which allows natural gas or crude oil producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.

Interstate Pipelines

We own an interstate natural gas pipeline, located in Wyoming. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of interstate pipelines extends to such matters as rates, services, and terms and conditions of service; the types of services offered to customers; the certification and construction of new facilities; the acquisition, extension, disposition or abandonment of facilities; the maintenance of

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accounts and records; relationships between affiliated companies involved in certain aspects of the natural gas business; the initiation and continuation of services; market manipulation in connection with interstate sales, purchases or transportation of natural gas; and participation by interstate pipelines in cash management arrangements. Natural gas companies are prohibited from charging rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

Under the NGA, the rates for service on interstate facilities must be just and reasonable and not unduly discriminatory. The FERC has granted the Rendezvous interstate natural gas pipeline market-based rate authority, subject to certain reporting requirements. In the event the FERC were to suspend our market-based rate authority, it could have an adverse impact on our revenue associated with the transportation service.

The Rendezvous interstate natural gas pipeline is subject to a number of FERC rules and policies, including certain of FERC’s standards of conduct from which it has previously received a partial waiver, and market behavior rules. In 2008, FERC issued Order No. 717, a final rule that implements standards of conduct that include three primary rules: (1) the “independent functioning rule,” which requires transmission function and marketing function employees to operate independently of each other; (2) the “no-conduit rule,” which prohibits passing transmission function information to marketing function employees; and (3) the “transparency rule,” which imposes posting requirements to help detect any instances of undue preference. FERC also clarified in Order No. 717 that existing waivers to the standards of conduct shall continue in full force and effect. FERC has issued a number of orders clarifying certain provisions of the Standards of Conduct under Order No. 717, however the subsequent orders did not substantively alter the Standards of Conduct.

Market Behavior Rules; Posting and Reporting Requirements

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provision of the EPAct 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, the FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines. In addition, the Commodities Futures Trading Commission (CFTC), is directed under the Commodities Exchange Act (CEA), to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC

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also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.

The EPAct of 2005 also added a Section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, the FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to the FERC’s jurisdiction, to provide by May 1 of each year an annual report to the FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.

Petroleum Pipelines

Our crude oil pipeline located in Wyoming is a common carrier of crude oil subject to regulation by various federal agencies. The FERC regulates interstate pipeline transportation of crude oil, petroleum products and other liquids, such as NGLs, under the ICA and EPAct 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on petroleum pipelines be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. In accordance with FERC regulations, we file transportation rates and terms and conditions of service with the FERC. Under the ICA, interested persons may challenge new or changed rates or services. The FERC is authorized to investigate such charges and may suspend the effectiveness of a challenged rate for up to seven months. A successful rate challenge could result in a petroleum pipeline paying refunds together with interest for the period that the rate was in effect. The FERC may also investigate, upon complaint or on its own motion, existing rates and related rules and may order a pipeline to change them prospectively. A shipper may obtain reparations for damages sustained for a period up to two years prior to the filing of a complaint.

EPAct 1992 required the FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, the FERC adopted an indexed rate methodology, which, as currently in effect, allows interstate petroleum pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI, as provided by the U.S. Department of Labor, Bureau of Labor Statistics. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 2.65%. The indexing methodology is applicable to existing rates with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but is permitted to do so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

The FERC has generally not investigated rates on its own initiative when those rates have not been the subject of a protest or a complaint by a shipper. If our rate levels were investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of costs, including the overall cost of service, including operating costs and overhead; the allocation of overhead and other administrative and general expenses to the regulated entity; the appropriate capital structure to be utilized in calculating rates; the appropriate rate of return on equity and interest rates on debt; the rate base, including the proper starting rate base; the throughput underlying the rate; and the proper allowance for federal and state income taxes.

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Environmental Matters

General

Our operation of pipelines and other facilities for the gathering of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

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requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;

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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

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delaying system modification or upgrades during permit reviews;

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requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

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enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or permit requirements imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Wastes

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, non-hazardous and hazardous solid wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of non-hazardous and hazardous solid waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For

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instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both non-hazardous and hazardous solid wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. We generate little hazardous waste; however, it is possible that some or all of the waste we currently generate and that are classified as non-hazardous wastes will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Act

In 1994, the EPA adopted regulations under the Oil Pollution Act of 1990, or OPA. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure Plan, or SPCC, for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We believe that none of our facilities is materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Air Emissions

Our operations are subject to the federal Clean Air Act, or the CAA, and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations and processing plants, and also impose various

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monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA proposed a final rule on June 7, 2012. The EPA finalized the proposed amendments on January 14, 2013, but the rule has not yet been published in the Federal Register, and will not become effective until 60 days after it is published. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. Compliance with the final rule currently is required by October 2013. We are continuing our evaluation of the cost impacts of the final rule and amendments.

On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. The EPA issued minor amendments to the rule on January 14, 2013. We are currently evaluating the impact that this final rule and amendments will have on our operations.

On August 16, 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. This new rule addresses emissions of various pollutants frequently associated with oil and natural gas production and processing activities. These final rules require, among other things, the reduction of volatile organic compound emissions from 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 use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. In addition, these regulations revise existing requirements for volatile organic compound emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million, and requires monitoring of connectors, pumps, pressure relief devices and open-ended lines. These regulations also establish requirements regarding emissions from: (i) wet seal and reciprocating compressors at gathering systems, boosting facilities, and onshore natural gas processing plants, effective October 15, 2012; (ii) specified pneumatic controllers at onshore oil and natural gas production well sites, gathering systems, boosting facilities, and onshore natural gas processing plants, effective October 15, 2013; and (iii) specified storage vessels at onshore oil and natural gas production well sites, gathering systems, boosting facilities, onshore natural gas processing plants, onshore natural gas transmission systems, and underground natural gas storage facilities, effective October 15, 2013. However, the EPA published a proposed rule on April 12, 2013 that would extend the compliance date for controlling

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regulated emissions from storage vessels constructed, modified or re-constructed after April 12, 2013 to the later of April 15, 2014 or 60 days after startup and allowing those storage vessels constructed, modified or re-constructed between August 23, 2011 and April 15, 2013 to only provide notice of their existence by October 15, 2013 unless their emissions increase after April 15, 2013, in which event the April 14, 2014 date would apply to them as well. 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. 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.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals except in accordance with the terms of a permit issued by the EPA or state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Safe Drinking Water Act

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the federal Safe Drinking Water Act, which establishes requirements for permitting, testing, monitoring, recordkeeping and reporting of injection well activities as well as a prohibition against the migration of fluid containing any contaminants into underground sources of drinking water. State programs may have analogous permitting and operational requirements. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We believe that our facilities will not be materially adversely affected by such requirements.

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Endangered Species

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas.

National Environmental Policy Act

The National Environmental Policy Act, or NEPA, establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and on March 12, 2012 issued final guidance that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

Climate Change

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as GHGs and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including NGLs fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility. We monitor and report our GHG emissions.

In addition, on September 2009, the EPA issued a final rule requiring the reporting of GHGs from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. Several of our onshore compression facilities will likely be required to report under this rule, with the first report due to the EPA in 2013.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes

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comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for our processing services. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our processing services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur in areas where we operate, they could have in adverse effect on our assets and operations.

The majority of scientific studies on climate change suggest that stronger storms may occur in the future in the areas where we operate, although the scientific studies are not unanimous. We are taking steps to mitigate physical risks from storms, but no assurance can be given that future storms will not have a material adverse effect on our business.

Hydraulic Fracturing

Substantially all of our customers’ 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 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 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, with a final report expected to be issued in 2016. 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 to better protect the environment from drilling using hydraulic fracturing completion methods. 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.

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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 sixty days of well stimulation. 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 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 use the REC techniques, with or with combustion devices, after January 1, 2015. However, 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. 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.

Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an

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Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered in the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

Title to Properties and Permits

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. With respect to any consents, permits, or authorizations that have not been obtained, our general partner believes that these consents, permits, or authorizations will be obtained after the closing of this offering, or that the failure to obtain these consents, permits, or authorizations will not have a material adverse effect on the operation of our business.

Our general partner believes that we will have satisfactory title to all of the assets that will be contributed to us at the closing of this offering. Under our omnibus agreement, QEP will indemnify us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business. Record title to some of our assets may continue to be held by affiliates of QEP until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. We will make these filings and obtain these consents upon completion of this offering. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions, and other encumbrances to which the underlying properties were subject at the time of acquisition by our Predecessor or us, our general partner believes that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.

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Employees

We are managed and operated by the board of directors and executive officers of QEP Midstream Partners GP, LLC, our general partner. Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner. Immediately after the closing of this offering, we expect that our general partner and its affiliates will have approximately 250 employees performing services for our operations. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

Legal Proceedings

Our gathering systems are the subject of ongoing litigation between Questar Gas Company (QGC) and QEP Field Services Company, Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. 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 1993 gathering agreement (1993 Agreement) executed when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services to QGC. 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 Field Services. As of March 31, 2013, our Predecessor has recorded $4.9 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. QGC may seek to amend its complaint to add us as a defendant in the litigation. Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

In addition to pending litigation, we may, from time to time, be involved in additional litigation and claims arising out of our operations in the normal course of business. Except as discussed above, we are not aware of any significant legal or governmental claims or assessments that are pending or threatened against us.

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MANAGEMENT

Management of QEP Midstream Partners, LP

We are managed by the directors and executive officers of our general partner, QEP Midstream Partners GP, LLC. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. QEP indirectly owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Immediately following the closing of this offering, our general partner will have five directors. QEP will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have at least three independent directors within one year of the date our common units are first listed on the NYSE. Our board has determined that Susan O. Rheney is independent under the independence standards of the NYSE.

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner, but we sometimes refer to these individuals in this prospectus as our employees.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each committee of the board of directors will have the composition and responsibilities described below.

Audit Committee

Susan O. Rheney, Charles B. Stanley and Richard J. Doleshek will serve as the initial members of our audit committee. Ms. Rheney will serve as the initial chair of our audit committee, and she satisfies the SEC and NYSE rules regarding independence and as the audit committee financial expert. Our general partner will rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. In compliance with those rules, Mr. Stanley will resign from the audit committee upon the appointment of the first such additional independent director, and Mr. Doleshek will resign from the audit committee when the final independent director is appointed. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.

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Conflicts Committee

At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. Susan O. Rheney will serve as the initial member and chair of our conflicts committee. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our incentive compensation plan. We anticipate that once appointed to our general partner’s board of directors, the additional independent members appointed to our audit committee will also serve on the conflicts committee. Any matters approved by our conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Directors and Executive Officers of QEP Midstream Partners GP, LLC

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of QEP Midstream Partners GP, LLC:


Name	Age		Position with QEP Midstream Partners GP, LLC
Charles B. Stanley		54	Chairman of the Board of Directors, President and Chief Executive Officer
Richard J. Doleshek		54	Director, Executive Vice President and Chief Financial Officer
Perry H. Richards		52	Director, Senior Vice President and General Manager
Abigail L. Jones		52	Vice President, Compliance and Corporate Secretary
Kendall K. Carbone		47	Vice President, Controller and Chief Accounting Officer
S. Scott Gutberlet		49	Director
Susan O. Rheney		53	Director

Charles B. Stanley. Charles B. Stanley was appointed President, Chief Executive Officer and chairman of the board of directors of our general partner in April 2013. Mr. Stanley has served as President, Chief Executive Officer and a director of QEP since June 2010. He served as Executive Vice President and Chief Operating Officer of Questar Corporation (“Questar”) from 2002 until QEP’s spin-off in June 2010. Mr. Stanley will devote the majority of his time to his roles at QEP and will also spend time, as needed, directly managing our business and affairs. Initially, we expect approximately 20% of his total business time will be devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops. Mr. Stanley also served as a director of Questar from 2002 until QEP’s spin-off in June 2010. Prior to joining Questar, he served as President, Chief Executive Officer and a director of El Paso Oil and Gas Canada, an upstream oil and gas company from 2000 to 2002, and as President and Chief Executive Officer of Coastal Gas International Company, a midstream infrastructure development company, from 1995 to 2000. He is a director of Hecla Mining Company and serves on the boards of various natural gas industry trade organizations, including America’s Natural Gas Alliance and the American Exploration and Production Council. In concluding that Mr. Stanley is qualified to serve as a director, the board considered, among other things, his more than 28 years of experience in the international and domestic upstream and midstream oil and gas industry.

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Richard J. Doleshek. Richard J. Doleshek was appointed as a Director and Executive Vice President and Chief Financial Officer of our general partner in April 2013. Mr. Doleshek has served as Executive Vice President, Chief Financial Officer and Treasurer of QEP since June 2010. He served as Executive Vice President, Chief Financial Officer of Questar from 2009 until QEP’s spin-off in June 2010. Mr. Doleshek will devote the majority of his time to his roles at QEP and will also spend time, as needed, directly managing our business and affairs. Initially, we expect approximately 20% of his total business time will be devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops. Prior to joining Questar, Mr. Doleshek was Executive Vice President and Chief Financial Officer of Hilcorp Energy Company from 2001 to 2009. In concluding that Mr. Doleshek is qualified to serve as a director, the board considered, among other things, his more than 30 years of experience upstream and midstream oil and gas industry.

Perry H. Richards. Perry H. Richards was appointed as a Director and Senior Vice President and General Manager of our general partner in April 2013. He has served as Senior Vice President of QEP since June 2010 and is responsible for managing QEP Field Services Company, a subsidiary of QEP. Mr. Richards will devote the majority of his time to his roles at QEP and will also spend time, as needed, directly managing our business and affairs. Initially, we expect approximately 30% of his total business time will be devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops. Mr. Richards previously served as Vice President, Questar Gas Management Company from 2005 until assuming his current position in June 2010. In concluding that Mr. Richards is qualified to serve as a director, the board considered, among other things, his more than 30 years of experience upstream and midstream oil and gas industry.

Abigail L. Jones. Abigail L. Jones was appointed Secretary and Vice President of Compliance of our general partner in April 2013. Ms. Jones has served as Corporate Secretary and Vice President of Compliance of QEP since June 2010. Ms. Jones will devote the majority of her time to her roles at QEP and will also spend time, as needed, directly managing our business and affairs. Initially, we expect approximately 20% of her total business time will be devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops. Ms. Jones served as Corporate Secretary and Vice President of Compliance of Questar from 2007 until QEP’s spin-off in June 2010. Ms. Jones joined the Legal Department of Questar in 2002. In 2004, she became Assistant Corporate Secretary, and in 2005, she became Corporate Secretary of Questar. In 2007, she assumed the role of Vice President, Compliance for Questar.

Kendall K. Carbone. Kendall K. Carbone was appointed Vice President, Controller and Chief Accounting Officer of our general partner in April 2013. Ms. Carbone has served as Vice President, Controller and Chief Accounting Officer of QEP since June 2012. Ms. Carbone will devote the majority of her time to her roles at QEP and will also spend time, as needed, directly managing our business and affairs. Initially, we expect approximately 10% of her total business time will be devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops. Ms. Carbone joined QEP in 2010 as Director of Finance and was promoted to Assistant Controller in August 2011 and served in that position until assuming her current role at QEP in June 2012. Prior to joining QEP, Ms. Carbone was the Director of Finance for the Refining and Marketing Division of Suncor Energy USA from 2003 to 2009 and served as Director of Sales and Marketing of Suncor Energy USA from 2009 until joining QEP in 2010. Ms. Carbone holds an active CPA license in the State of Colorado.

S. Scott Gutberlet. S. Scott Gutberlet was appointed as a Director of our general partner in April 2013. Mr. Gutberlet has served as Vice President of Commercial and Technical Services of QEP Energy Company, a subsidiary of QEP, since April 2012. Mr. Gutberlet joined the reservoir engineering department of Questar in 2006. In 2007, he became the Director of Midstream Commercial and Technical Operations and, in 2008, he became the General Manager of the Uinta Basin Division for Questar Exploration & Production Company. He then served as Director, Investor Relations for QEP until assuming his current position. In concluding that Mr. Gutberlet is qualified to serve as a director, the board

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considered, among other things, his more than 26 years of experience upstream and midstream oil and gas industry.

Susan O. Rheney. Susan O. Rheney was appointed as an independent Director of our general partner in June 2013. Ms. Rheney is currently a private investor. Ms. Rheney has served as a member of the board of directors of CenterPoint Energy, Inc. since 2008. She served on the board of Genesis Energy, Inc., the general partner of Genesis Energy, LP, a publicly traded limited partnership, from 2002 to 2010. From 2003 to 2005, Ms. Rheney served as a member of the board of directors of Cenveo, Inc. and served as chairman of the board from January to August 2005. From 1987 to 2001, Ms. Rheney served as a principal in the Sterling Group, a company specializing in leveraged buyout transactions in a variety of industries, including chemicals, agriculture and basic manufacturing. In concluding that Ms. Rheney is qualified to serve as a director, the board considered, among other things, her extensive financial knowledge and her experience as a director for companies in the energy industry.

Board Leadership Structure

The chief executive officer of our general partner currently serves as the chairman of the board. The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by QEP. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies that management has implemented to monitor such exposures.

Executive Compensation

We and our general partner were formed in April 2013 and have not accrued any obligations with respect to compensation for directors and officers for the 2013 fiscal year or for any prior period. In addition, we do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, the executive officers of which are employees of QEP. Prior to the completion of this offering, we and our general partner will enter into the omnibus agreement with QEP, pursuant to which, among other matters:

•

QEP will make available to our general partner the services of the QEP employees who will serve as the executive officers of our general partner; and

•

Our general partner will pay fixed management fees to QEP or one of its affiliates to cover, among other things, the services provided to us by the QEP employees who will serve as the executive officers of our general partner.

Pursuant to the applicable provisions of our partnership agreement, we will reimburse our general partner for the costs it incurs in relation to the QEP employees, including executive officers, who provide services to operate our business.

Following the closing of this offering, we expect that our Named Executive Officers, or NEOs, which individuals include our general partner’s chief executive officer and our next two most highly compensated executive officers, will consist of the following individuals:

•

Charles B. Stanley, our President and Chief Executive Officer,

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•

Richard J. Doleshek, our Executive Vice President and Chief Financial Officer, and

•

Perry H. Richards, our Senior Vice President and General Manager.

We expect that each of these NEOs will continue to perform services for our general partner, as well as QEP and its affiliates, after the completion of this offering, and that the NEOs will initially devote less than a majority of their total working time to our business. Specifically, we currently expect that Messrs. Stanley and Doleshek will devote approximately 20% of their working time to matters relating to our business and that Mr. Richards will devote approximately 30% of his working time to matters relating to our business, provided that these percentages are subject to change as we continue to determine our executive management needs in connection with this offering and following this offering as our business may grow or evolve over time.

Following the closing of this offering, our NEOs will continue to participate in QEP’s compensation programs and, except with respect to awards granted under our LTIP, which is described in more detail below under the heading “— Long-Term Incentive Plan,” the NEOs will not receive separate amounts of compensation in relation to their services provided to us pursuant to the omnibus agreement. In addition, except with respect to awards granted under our LTIP, neither we nor our general partner will provide any input on compensation amounts to be paid to our NEOs.

The amount that will be charged to us for the services of our NEOs is based on a fixed dollar amount and is agreed upon and set by the terms of the omnibus agreement, subject to adjustment from time to time in accordance with the terms thereof. As provided in the omnibus agreement, the annualized fixed fee for each of our NEOs is initially as follows: for Mr. Stanley, $ ; for Mr. Doleshek, $ ; and for Mr. Richards, $ . Please read “Certain Relationships and Related Party Transactions — Agreements Relating to Our Operations — Omnibus Agreement” for a further description of the omnibus agreement.

Compensation paid or awarded by us in 2013 with respect to our NEOs will reflect only the annualized fixed fee for our NEOs as described above, plus any awards that our general partner may determine to grant to our NEOs under our LTIP.

Long-Term Incentive Plan

Our general partner intends to adopt the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan, or our LTIP, for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the plan, which awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following is a general description of the terms that are included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the plan administrator, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to common

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units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

Awards granted to grantees who are partners, or granted to grantees in anticipation of the grantee becoming a partner or granted as otherwise determined by the administrator, may consist of profits interest units. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of an other unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other

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measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the administrator deems appropriate to reflect the applicable transaction or event.

Termination of Employment

The consequences of the termination of a grantee’s employment, membership on our general partner’s board of directors or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Amendment or Termination of Long-Term Incentive Plan

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

Other Policies

Prohibition on Derivatives and Hedging

In order to ensure that executive officers or our general partner, including our NEOs, bear the full risks of our common unit ownership, we expect our executive officers will be subject to a policy that prohibits hedging transactions related to our units or pledging or creating a security interest in any of our units, including units in excess of any ownership requirement we may adopt.

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Recoupment/Clawback Policy

We are currently considering the terms and conditions of a compensation clawback policy, pending expected regulatory action on this issue, and expect that any such policy will be intended to comply with all applicable regulations and other legal requirements.

Director Compensation

The officers or employees of our general partner or of QEP who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers or employees of our general partner or of QEP will receive compensation as set by our general partner’s board of directors from time to time. Upon joining our general partner’s board, each non-employee director is expected to receive an initial award of common units granted under our LTIP having a value of $65,000. In addition, the annual compensation package for our non-employee directors is initially expected to have an aggregate value of $130,000, of which 50% will be paid in cash on a quarterly basis and 50% will be paid in the form of an annual award of common units granted under our LTIP. The chair of each standing committee of our general partner’s board will also receive an additional $10,000 annual cash retainer. Our general partner’s board of directors also expects to adopt unit ownership guidelines for our non-employee directors, pursuant to which they will be required to hold common units in us having value of at least three times the regular annual cash retainer amount. Non-employee directors will have a period of five years from the date of appointment to the board to achieve the stated ownership requirements. In addition, non-employee directors will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees.

Each director will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of QEP Midstream Partners, LP that will be issued upon the consummation of this offering and the related transactions and held by beneficial owners of 5.0% or more of the units, by each director of QEP Midstream Partners GP, LLC, our general partner, by each named executive officer and by all directors and officers of our general partner as a group and assumes no exercise of the underwriters’ option to purchase additional common units.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of , 2013, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The percentage of units beneficially owned is based on a total of common units and subordinated units outstanding immediately following this offering.

Name of Beneficial Owner(1)

Common
Units to Be
Beneficially
Owned

Percentage
of Common
Units to Be
Beneficially
Owned

Subordinated
Units to Be
Beneficially
Owned

Percentage
of Subordinated
Units to Be
Beneficially
Owned

Percentage
of Total
Common
Units and
Subordinated
Units to Be
Beneficially
Owned

QEP Resources, Inc.

100

Directors/Named Executive Officers

Charles B. Stanley

Richard J. Doleshek

Perry H. Richards

S. Scott Gutberlet

Susan O. Rheney

All Directors and Executive Officers as a group ( persons)

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is 1050 17th Street, Suite 500, Denver, Colorado 80265.

The following table sets forth the number of shares of QEP common stock beneficially owned as of , 2013, except as otherwise noted, by each director, by each named executive officer and by all directors and executive officers of our general partner as a group:


Name of Beneficial Owners	Amount and Nature of Beneficial Ownership*	Percent of Total Outstanding
Directors/Named Executive Officers
Charles B. Stanley			*
Richard J. Doleshek			*
Perry H. Richards			*
S. Scott Gutberlet			*
Susan O. Rheney
All Directors and Executive Officers as a group ( persons)			*

*	The percentage of shares beneficially owned by each director or each executive officer does not exceed 1% of the common shares outstanding. The percentage of shares beneficially owned by all directors and executive officers as a group does not exceed 1% of the common shares outstanding.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, the general partner and its affiliates will own common units and subordinated units representing a % limited partner interest in us. In addition, our general partner will own general partner units representing a 2.0% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of QEP Midstream Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering for the contribution of the assets and liabilities to us

•

common units;

•

subordinated units;

•

general partner units representing a 2.0% general partner interest in us;

•

the incentive distribution rights;

•

$ million cash distribution of the net proceeds of the offering, in part to reimburse them for certain capital expenditures; and

•

the right to have up to common units redeemed with the proceeds of any exercise of the underwriters’ option to purchase additional common units.

Operational Stage

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions of 98.0% to the unitholders pro rata, including QEP, as holder of an aggregate of common units and subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $ million on the 2.0% general partner interest and $ million on their common units and subordinated units.

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Payments to our general partner and its affiliates

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 and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will pay to QEP an annual amount for providing certain general and administrative services to us, which includes a fixed annual fee for certain executive management services by certain officers of our general partner. Other portions of the annual amount will be based on the costs actually incurred by QEP and its affiliates in providing the services. We will also reimburse QEP for any additional out-of-pocket costs and expenses incurred by QEP and its affiliates in providing general and administrative services to us. For the twelve months ending June 30, 2014, we estimate that these expenses will be approximately $16.3 million, which includes, among other items, compensation expense for all employees required to manage and operate our business. Please read “— Agreements Governing the Transactions — Omnibus Agreement” below and “Management — Executive Compensation.”

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement — Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various agreements that will affect the transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements 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. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid for with the proceeds of this offering.

Omnibus Agreement

At the closing of this offering, we will enter into an omnibus agreement with QEP, certain of its subsidiaries and our general partner that will address the following matters:

•

our payment of an annual amount to QEP, initially in the amount of approximately $ million, for providing certain general and administrative services by QEP and its affiliates, which annual amount

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includes a fixed annual fee of approximately $ million for providing certain executive management services by certain officers of our general partner. Other portions of this annual amount will be based on the costs actually incurred by QEP and its affiliates in providing the services;

•

our obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement), as well as any other out-of-pocket expenses incurred by QEP on our behalf;

•

an indemnity by QEP for certain environmental and other liabilities, and our obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of our assets that occur after the closing of this offering and for environmental liabilities related to our assets to the extent QEP is not required to indemnify us; and

•

so long as QEP controls our general partner, the omnibus agreement will remain in full force and effect. If QEP ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of Annual Fee and Reimbursement of Expenses

We will pay QEP, in equal monthly installments, the annual amount QEP estimates will be payable by us to QEP during that calendar year for providing services for our benefit. We will reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services to us. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Indemnification

Under the omnibus agreement, QEP will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before the closing of this offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of this offering and identified prior to the third anniversary of the closing of this offering, and will be subject to an aggregate deductible of $500,000 before we are entitled to indemnification. There is no cap on the amount for which QEP will indemnify us under the omnibus agreement with respect to environmental claims once we meet the deductible, if applicable. QEP will also indemnify us for certain defects in title to the assets contributed to us and failure to obtain certain consents, licenses and permits necessary to conduct our business, including the cost of curing any such condition.

QEP will also indemnify us for liabilities relating to:

•

the assets contributed to us, other than environmental liabilities, that arise out of the ownership or operation of the assets prior to the closing of this offering and that are asserted prior to the third anniversary of the closing of this offering;

•

events and conditions associated with any assets retained by QEP; and

•

all tax liabilities attributable to the assets contributed to us arising prior to the closing of this offering or otherwise related to QEP’s contribution of those assets to us in connection with this offering.

Competition

Under our partnership agreement, QEP and its affiliates are expressly permitted to compete with us. QEP and any of its affiliates may acquire, construct or dispose of additional gathering systems or other midstream assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

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Other Agreements with QEP and Related Parties

Gathering Agreements

We are party to 24 gathering agreements for natural gas, oil, water and condensate with QEP. Our gathering agreements with QEP generally fall into three categories: (i) “life-of-reserves” agreement, (ii) long-term agreements, with remaining primary terms ranging from 1 to 13 years, and month-to-month thereafter and (iii) month-to-month or year-to-year evergreen agreements. Our gathering agreements are fee-based agreements, pursuant to which we provide gathering and, as applicable, compression services on a specified per MMBtu or per barrel basis. The gathering fee varies by agreement, and the majority of our agreements include annual inflation adjustment mechanisms.

These gathering agreements accounted for approximately 40% of our gathering throughput for the year ended December 31, 2012 and approximately 50% of our gathering throughput for the three months ended March 31, 2013. Approximately 50% of our natural gas gathering volumes and 33% of our crude oil volumes were comprised of production owned by QEP. For the year ended December 31, 2012 and the three months ended March 31, 2013, QEP accounted for approximately 52% and 55%, respectively, of our gathering revenues.

Acreage Dedication

Several of our gathering agreements with QEP contain acreage dedications. Pursuant to the terms of these agreements, QEP has dedicated to us all of the oil and natural gas production it owns or controls 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 agreement and located within the dedicated acreage as our gathering systems currently exist and as they are expanded to connect to additional wells.

Minimum Volume Commitments

Three of our gathering agreements with QEP contain minimum volume commitments pursuant to which QEP guarantees to ship a minimum volume of natural gas or oil on our gathering systems. The original terms of the minimum volume commitments range from 10 to 15 years.

If QEP’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. 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 QEP’s actual throughput volumes exceed its minimum volume commitment for the applicable period, there is a crediting mechanism that allows QEP 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 shortfall payments varies, ranging from the subsequent minimum volume commitment year to the full term of the agreement.

Condensate Sales Agreements

In connection with this offering, we expect to enter into five-year condensate sales agreements with QEP. Pursuant to the terms of these agreements, we expect to sell substantially all of our condensate to QEP at a fixed priced in order to minimize our commodity exposure. We expect these sales agreements to account for approximately 6% of our revenue, consistent with historical sales.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner will adopt a related party transactions policy in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions

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that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including QEP, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner that is not adverse to the best interests of its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner that is not adverse to the best interests of our partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. There is no requirement that our general partner seek the approval of the conflicts committee for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•

approved by the conflicts committee;

•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•

fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner does not seek approval from the conflicts committee and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is not adverse to the best interests of the partnership or meets the specified standard, for example, a transaction on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties. Please read “Management — Management of QEP Midstream Partners, LP — Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

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.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of

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which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including QEP, are not prohibited from engaging in other businesses or activities, including those that might compete with us.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors and QEP. 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. Therefore, QEP may compete with us for acquisition opportunities and may own an interest in entities that compete with us.

Our General Partner is Allowed to Take Into Account the Interests of Parties Other Than Us, Such as QEP, in Resolving Conflicts of Interest.

Our partnership agreement contains provisions that reduce and modify the standards to which our general partner would otherwise be held by state fiduciary duty law. 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 duty or obligation 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 partners where the language in our partnership agreement does not provide for a clear course of action. This 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 or any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right, its voting rights with respect to the units it owns and its registration rights, and its determination whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.

Our Partnership Agreement Replaces the Fiduciary Duties that Would Otherwise be Owed By Our General Partner with Contractual Standards Governing Its Duties, and Limits Our General Partner’s Liabilities and the Remedies Available to Our Unitholders for Actions That, Without the Limitations, Might Constitute Breaches of Fiduciary Duty Under Applicable Delaware Law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware law. For example, our partnership agreement:

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. Examples of decisions that our general partner may make in its individual capacity include: (1) how to allocate business opportunities among us and its other affiliates; (2) whether to exercise its limited call right; (3) how to exercise its voting rights with respect to the units it owns; (4) whether to exercise its registration rights; (5) whether to elect to reset target distribution levels; and (6) whether or not to consent to any merger or consolidation of the partnership or amendment to our partnership agreement;

•

provides that the general partner will have no liability to us or our limited partners for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

•

generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any determination by our general partner must be made in good faith. If an affiliate

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transaction or the resolution of another conflict of interest is not approved by our public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

•

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 or directors, as the cases 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 unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

Except in Limited Circumstances, Our General Partner Has the Power and Authority to Conduct Our Business Without Unitholder Approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

•

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

•

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

•

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

•

the negotiation, execution and performance of any contracts, conveyances or other instruments;

•

the distribution of our cash;

•

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

•

the maintenance of insurance for our benefit and the benefit of our partners;

•

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

•

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

•

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

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•

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

•

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must subjectively believe that the determination is not adverse to the best interests of our partnership. Please read “Our Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Actions Taken by Our General Partner May Affect the Amount of Cash Available for Distribution to Unitholders or Accelerate the Right to Convert Subordinated Units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

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the amount and timing of asset purchases and sales;

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cash expenditures;

•

borrowings;

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the issuance of additional units; and

•

the creation, reduction or increase of reserves in any quarter.

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

In addition, our general partner may use an amount, initially equal to $ million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

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accelerating the Expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow working capital funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordinated Units and Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

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We Will Reimburse Our General Partner and Its Affiliates for Expenses.

We will reimburse our general partner and its affiliates, including QEP, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. Our omnibus agreement with QEP also address our payment of annual amounts to, and our reimbursement of, our general partner and its affiliates for these costs and services. Please read “Certain Relationships and Related Party Transactions.”

Contracts Between Us, on the One Hand, and Our General Partner and Its Affiliates, on the Other Hand, Will Not Be the Result of Arm’s-Length Negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the close of this offering. While neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with our general partner and its affiliates will be generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. 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 terms that are more favorable without the limitation on liability.

Common Units Are Subject to Our General Partner’s Limited Call Right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “Our Partnership Agreement — Limited Call Right.”

Common Unitholders Will Have No Right to Enforce Obligations of Our General Partner and Its Affiliates Under Agreements with Us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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Our General Partner Decides Whether to Retain Separate Counsel, Accountants or Others to Perform Services for Us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or our conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 Our Conflicts Committee or Our Unitholders. This Election May Result in Lower Distributions to Our Common Unitholders in Certain Situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive calendar quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Furthermore, our general partner has the right to transfer all or any portion of the 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 resetting target distributions have been fulfilled. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two calendar quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”

Duties of the General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate, except for the implied contractual covenant of good faith and fair dealing, the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

As permitted by the Delaware Act, 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 our general partner and contractual methods of resolving conflicts of interest. We

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have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has duties to manage our general partner in a manner that is not adverse to the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was not adverse to the best interests of our partnership, and will not be subject to any other standard under applicable law, other than the implied contractual covenant of good faith and fair dealing. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving

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a vote of unitholders or that are not approved by our conflicts committee must be:

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on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

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“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

If our general partner does not seek approval from our conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors 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 unlawful.

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with

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knowledge that the conduct was unlawful. We also must provide this indemnification for criminal proceedings when our general partner or these other persons acted with no knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

Wells Fargo Shareowner Services will serve as the registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:

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surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

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special charges for services requested by a holder of a common unit; and

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other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

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automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

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represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and

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gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

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with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

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with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

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with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

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with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on April 19, 2013 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of gathering natural gas, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.” For a discussion of our general partner’s right to contribute capital to maintain its 2.0% general partner interest if we issue additional units, please read “— Issuance of Additional Securities.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters that require the approval of a “unit majority” require:

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during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

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after the subordination period, the approval of a majority of the outstanding common units.

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In voting their common units and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

Issuance of additional units

No approval rights.

Amendment of our partnership agreement

Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority. Please read “— Merger, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please read “— Termination and Dissolution.”

Withdrawal of the general partner

Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to , 2023 in a manner which would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”

Removal of the general partner

Not less than 66²/₃% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest

Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to , 2023. Please read “— Transfer of General Partner Interest.”

Transfer of incentive distribution rights

Our general partner may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “— Transfer of Incentive Distribution Rights.”

Reset of incentive distribution levels

No approval right.

Transfer of ownership interests in our general partner

No approval right. Please read “— Transfer of Ownership Interests in Our General Partner.”

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right of, by the limited partners as a group:

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to remove or replace our general partner;

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to approve some amendments to our partnership agreement; or

•

to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interests in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

Upon issuance of additional limited partner interests (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of common units in connection with a rest of the incentive distribution target levels or the issuance of common units upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us 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. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

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enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

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The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the completion of this offering and the transactions contemplated thereby, our general partner and its affiliates will own approximately % of the outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

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a change in our name, the location of our principal office, our registered agent or our registered office;

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the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

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a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (ERISA), whether or not substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

•

an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

•

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

•

a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

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mergers with, conveyances to or conversions into another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

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do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

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are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

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are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

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are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain such an opinion of counsel.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90.0% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

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

A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20.0% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or

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conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor;

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

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the entry of a decree of judicial dissolution of our partnership; or

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there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

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the action would not result in the loss of limited liability of any limited partner; and

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neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to , 2023 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after , 2023 our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ written notice to the limited partners if at least 50.0% of the outstanding units are

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held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/₃% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33¹/₃% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own % of the outstanding common and subordinated units.

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

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the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

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

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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 based on the fair market value of those interests as of the effective date of its removal.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including

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severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to (1) an affiliate of our general partner (other than an individual), or (2) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general partner interest to another person prior to , 2023 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, QEP and its affiliates may sell or transfer all or part of their membership interest in our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove QEP Midstream Partners GP, LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read “— Withdrawal or Removal of Our General Partner.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80.0% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ written notice.

The purchase price in the event of this purchase is the greater of:

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the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

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the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

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As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences — Disposition of Common Units.”

Redemption of Ineligible Holders

In order to avoid 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 FERC or analogous regulatory body, the general partner at any time can request a transferee or a unitholder to certify or re-certify:

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that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or

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that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

Furthermore, in order to avoid a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest as the result of any federal, state or local law or regulation concerning the nationality, citizenship or other related status of any unitholder, our general partner may at any time request unitholders to certify as to, or provide other information with respect to, their nationality, citizenship or other related status.

The certifications as to taxpayer status and nationality, citizenship or other related status can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a unitholder fails to furnish the certification or other requested information with 30 days or if our general partner determines, with the advice of counsel, upon review of such certification or other information that a unitholder does not meet the status set forth in the certification, we will have the right to redeem all of the units held by such unitholder at the market price as of the date three days before the date the notice of redemption is mailed.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5.0% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

Meetings; Voting

Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or

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by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class. Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

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our general partner;

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any departing general partner;

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any person who is or was an affiliate of our general partner or any departing general partner;

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any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, or any entity set forth in the preceding three bullet points;

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any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates; and

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any person designated by our general partner because such person’s status, service or relationship expose such person to claims or suits relating to our business and affairs.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.

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Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement.”

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 50 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

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a current list of the name and last known address of each record holder;

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copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

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certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of QEP Midstream Partners GP, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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Exclusive Forum

Our partnership agreement will provide that the Court of Chancery of the State of Delaware shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold an aggregate of common units and subordinated units (or common units and subordinated units if the underwriters exercise their option to purchase additional units in full). All of the subordinated units will convert into common units at the end of the subordination period. All of the common units and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act. Although none of the directors or officers of our general partner own any common units prior to this offering, they have contractually agreed not to sell units for a specified period from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

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1.0% of the total number of the common units outstanding, which will equal approximately units immediately after this offering; or

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the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

At the closing of this offering, the following common units will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act, Rule 144 or otherwise:

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common units owned by our general partner and its affiliates; and

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any units acquired by our general partner or any of its affiliates.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement — Issuance of Additional Securities.”

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Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-Up Agreements

QEP and certain of its affiliates, including our general partner and each of our general partner’s directors and officers, have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Wells Fargo Securities, LLC, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under the LTIP. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the Internal Revenue Code), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the Treasury Regulations) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to QEP Midstream Partners, LP and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units —Allocations Between Transferors and Transferees”) and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “—Uniformity of Units”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90.0% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90.0% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

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We will be classified as a partnership for federal income tax purposes; and

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Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

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Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

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For each taxable year, more than 90.0% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of QEP Midstream Partners, LP will be treated as partners of QEP Midstream Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of QEP Midstream Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in QEP Midstream Partners, LP. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in QEP Midstream Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “— Tax Consequences of Unit Ownership — Entity-Level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

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A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2015, 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 with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

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gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

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we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

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interest on indebtedness properly allocable to property held for investment;

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our interest expense attributed to portfolio income; and

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the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income

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includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of the intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted to take into account the unitholders’ share of nonrecourse debt, and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of this offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates (or by a third party) that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of

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Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

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his relative contributions to us;

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the interests of all the partners in profits and losses;

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the interest of all the partners in cash flow; and

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the rights of all the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units —Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

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any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

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any cash distributions received by the unitholder as to those units would be fully taxable; and

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while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, 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 borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26.0% on the first $179,500 of alternative minimum taxable income in excess of the exemption amount and 28.0% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Beginning on January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

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In addition, a 3.8% Medicare tax, or NIIT, on certain net investment income earned by individuals, estates and trusts applies for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income and (2) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income and (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide guidance regarding the NIIT. Although the proposed Treasury Regulations are effective for taxable years beginning after December 31, 2013, taxpayers may rely on the proposed Treasury Regulations for purposes of compliance until the effective date of the final regulations. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “— Disposition of Common Units — Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (inside basis) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets (common basis) and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150.0% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “— Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of

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aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

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Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called syndication expenses) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an

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individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “— Tax Consequences of Unit Ownership — Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

•

a short sale;

•

an offsetting notional principal contract; or

•

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units

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owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% 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

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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.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “— Tax Consequences of Unit Ownership — Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required

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to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30.0%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5.0% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50.0% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50.0% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated

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as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1.0% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1.0% interest in profits or by any group of unitholders having in the aggregate at least a 5.0% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (FDAP Income), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (Gross Proceeds) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders.

These rules generally will apply to payments of FDAP Income made on or after January 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read “— Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-US entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

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the name, address and taxpayer identification number of the beneficial owner and the nominee;

•

whether the beneficial owner is:

(1)

a person that is not a U.S. person;

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(2)

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(3)

a tax-exempt entity;

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20.0% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10.0% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

•

for which there is, or was, “substantial authority”; or

•

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150.0% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200.0% or more (or 50.0% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10.0% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200.0% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40.0%. We do not anticipate making any valuation misstatements.

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In addition, the 20.0% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40.0%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Administrative Matters — Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

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accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Administrative Matters — Accuracy-Related Penalties”;

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for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

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in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

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 “— 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.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Colorado, North Dakota, Utah and Wyoming. With exception of Wyoming, each of those states imposes an income tax on corporations and other entities and also imposes a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years.

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Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN QEP MIDSTREAM PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

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whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

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whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences — Tax-Exempt Organizations and Other Investors”; and

•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

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(c) there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25.0% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above. The foregoing discussion of issues arising for employee benefit plan investments under ERISA and the Internal Revenue Code is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Subject to the terms and conditions set forth in an underwriting agreement, we have agreed to sell to the underwriters named below, and the underwriters, for whom Wells Fargo Securities, LLC is acting as book running manager and representative, have severally agreed to purchase, the respective number of common units appearing opposite their names below:


Underwriters		Number of Common Units
Wells Fargo Securities, LLC

Total

All of the common units to be purchased by the underwriters will be purchased from us.

The underwriting agreement provides that the obligations of the several underwriters are subject to various conditions, including approval of legal matters by counsel. The common units are offered by the underwriters, subject to prior sale, when, as and if issued to and accepted by them. The underwriters reserve the right to withdraw, cancel or modify the offer and to reject orders in whole or in part.

The underwriting agreement provides that the underwriters are obligated to purchase all the common units offered by this prospectus if any are purchased, other than those common units covered by the option to purchase additional common units described below. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the non-defaulting underwriters may be increased or the underwriting agreement may be terminated.

Option to Purchase Additional Common Units

We have granted the underwriters an option, exercisable for 30 days after the date of the underwriting agreement, to purchase up to an additional common units from us at the initial public offering price less the underwriting discounts, as set forth on the cover page of this prospectus, and less any dividends or distributions declared, paid or payable on the common units that the underwriters have agreed to purchase from us but that are not payable on such additional common units. If the underwriters exercise this option in whole or in part, then the underwriters will be severally committed, subject to the conditions described in the underwriting agreement, to purchase the additional common units in proportion to their respective commitments set forth in the prior table.

The net proceeds from any exercise of the underwriters’ 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.

Discounts

The common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus and to certain dealers at that price less a concession of not more than $ per common unit. After the initial offering, the public offering price, concession and reallowance to dealers may be changed.

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The following table summarizes the underwriting discounts and the proceeds, before expenses, payable to us, both on a per unit basis and in total, assuming either no exercise or full exercise by the underwriters of their option to purchase additional common units:

Total

Per Common
Unit

Without
Option

With
Option

Public offering price

Underwriting discounts(1)

Proceeds, before expenses, to us

(1)	Excludes a structuring fee of approximately $ million ($ million if the underwriters exercise the option to purchase additional units in full) payable to Wells Fargo Securities, LLC for the evaluation, analysis and structuring of our partnership.

We estimate that the expenses of this offering payable by us, not including underwriting discounts and structuring fees, will be approximately $ .

Indemnification of Underwriters

The underwriting agreement provides that we will indemnify the underwriters against specified liabilities, including liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

Lock-Up Agreements

We, our general partner and certain of its affiliates, including QEP, and the directors and executive officers of our general partner have agreed, subject to certain exceptions, that, without the prior written consent of Wells Fargo Securities, LLC, we and they will not, during the period beginning on and including the date of this prospectus through and including the date that is 180 days after the date of this prospectus, directly or indirectly:

•

issue (in the case of us), offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of any of our common units or any securities convertible into or exercisable or exchangeable for our common units, except that we may issue common units or any securities convertible or exchangeable into our common units as payment of any part of the purchase price for businesses that we acquire; provided that any recipient of such common units must agree in writing to be bound by these provisions for the remainder of the lock-up period;

•

in the case of us, file or cause the filing of any registration statement under the Securities Act with respect to any of our common units or any securities convertible into or exercisable or exchangeable for our common units (other than (i) any Rule 462(b) registration statement filed to register securities to be sold to the underwriters pursuant to the underwriting agreement, (ii) any registration statement on Form S-8 to register common units or options to purchase common units pursuant to the long-term incentive plan, and (iii) any registration statement in connection with our entrance into a definitive agreement relating to an acquisition); or

•

enter into any swap or other agreement, arrangement, hedge or transaction that transfers to another, in whole or in part, directly or indirectly, any of the economic consequences of ownership of our common units or any securities convertible into or exercisable or exchangeable for our common units.

Wells Fargo Securities, LLC may, in its sole discretion and at any time or from time to time, without notice, release all or any portion of the common units or other securities subject to the lock-up agreements. Any determination to release any common units or other securities subject to the lock-up agreements would

206

be based on a number of factors at the time of determination, which may include the market price of the common units, the liquidity of the trading market for the common units, general market conditions, the number of common units or other securities proposed to be sold or otherwise transferred and the timing, purpose and terms of the proposed sale or other transfer. Wells Fargo Securities, LLC does not have any present intention, agreement or understanding, implicit or explicit, to release any of the common units or other securities subject to the lock-up agreements prior to the expiration of the lock-up period described above.

Electronic Distribution

This prospectus and the registration statement of which this prospectus forms a part may be made available in electronic format on the websites maintained by one or more of the underwriters. The underwriters may agree to allocate a number of common units for sale to their online brokerage account holders. The common units will be allocated to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

Other than the information set forth in this prospectus and the registration statement of which this prospectus forms a part, information contained in any website maintained by an underwriter is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been endorsed by us and should not be relied on by investors in deciding whether to purchase common units. The underwriters are not responsible for information contained in websites that they do not maintain.

New York Stock Exchange

We have applied to have our common units listed on the New York Stock Exchange under the symbol “QEPM.” The underwriters have undertaken to sell the minimum number of common units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange distribution requirements for trading.

Stabilization

In order to facilitate this offering of our common units, the underwriters may engage in transactions that stabilize, maintain or otherwise affect the market price of our common units. Specifically, the underwriters may sell more common units than they are obligated to purchase under the underwriting agreement, creating a short position. A short sale is covered if the short position is no greater than the number of common units available for purchase by the underwriters under their option to purchase additional common units. The underwriters may close out a covered short sale by exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out a covered short sale, the underwriters may consider, among other things, the market price of common units compared to the price payable under their option to purchase additional common units. The underwriters may also sell common units in excess of the number of common units available under their option to purchase additional common units, creating a naked short position. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after the date of pricing of this offering that could adversely affect investors who purchase in this offering.

As an additional means of facilitating this offering, the underwriters may bid for, and purchase, common units in the open market to stabilize the price of our common units, so long as stabilizing bids do not exceed a specified maximum. The underwriting syndicate may also reclaim selling concessions allowed to an underwriter or a dealer for distributing common units in this offering if the underwriting syndicate repurchases previously distributed common units to cover syndicate short positions or to stabilize the price of the common units.

207

The foregoing transactions, if commenced, may raise or maintain the market price of our common units above independent market levels or prevent or retard a decline in the market price of the common units.

The foregoing transactions, if commenced, may be effected on the New York Stock Exchange or otherwise. Neither we nor any of the underwriters makes any representation that the underwriters will engage in any of these transactions and these transactions, if commenced, may be discontinued at any time without notice. Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of the effect that the transactions described above, if commenced, may have on the market price of our common units.

Discretionary Accounts

The underwriters have informed us that they do not intend to confirm sales to accounts over which they exercise discretionary authority in excess of 5% of the total number of common units offered by them.

Pricing of This Offering

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for our common units was determined between us and the representative of the underwriters. The factors considered in determining the initial public offering price included:

•

prevailing market conditions;

•

our results of operations and financial condition;

•

financial and operating information and market valuations with respect to other companies that we and the representative of the underwriters believe to be comparable or similar to us;

•

the present state of our development; and

•

our future prospects.

An active trading market for our common units may not develop. It is possible that the market price of our common units after this offering will be less than the initial public offering price.

Relationships

Certain of the underwriters and their affiliates have provided, and may in the future provide, various investment banking, commercial banking, financial advisory and other financial services to us and our affiliates for which they have received, and may in the future receive, customary fees. Additionally, certain of the underwriters and their affiliates have engaged, and may from time to time in the future engage, in transactions with us in the ordinary course of their business.

This offering is being made in compliance with Rule 2310 of the Financial Industry Regulatory Authority, Inc., or FINRA, Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Sales Outside the United States

No action has been taken in any jurisdiction (except in the United States) that would permit a public offering of the securities, or the possession, circulation or distribution of this prospectus or any other material relating to us or the securities in any jurisdiction where action for that purpose is required. Accordingly, the securities may not be offered or sold, directly or indirectly, and none of this prospectus or any other offering material or advertisements in connection with the securities may be distributed or published, in or from any country or jurisdiction except in compliance with any applicable rules and regulations of any such country or jurisdiction.

Each of the underwriters may arrange to sell securities offered hereby in certain jurisdictions outside the United States, either directly or through affiliates, where they are permitted to do so. In that regard,

208

Wells Fargo Securities, LLC may arrange to sell securities in certain jurisdictions through an affiliate, Wells Fargo Securities International Limited, or WFSIL. WFSIL is a wholly owned indirect subsidiary of Wells Fargo & Company and an affiliate of Wells Fargo Securities, LLC. WFSIL is a U.K. incorporated investment firm regulated by the Financial Services Authority. Wells Fargo Securities is the trade name for certain corporate and investment banking services of Wells Fargo & Company and its affiliates, including Wells Fargo Securities, LLC and WFSIL.

209

VALIDITY OF THE COMMON UNITS

The validity of our common units will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of QEP Midstream Partners, LP Predecessor as of December 31, 2012 and December 31, 2011 and for each of the two years in the period ended December 31, 2012 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of QEP Midstream Partners, LP at April 19, 2013 included in this prospectus has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information described in the registration statement and related exhibits, portions of which have been omitted as permitted by the rules and regulations of the SEC. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website on the internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www. .com and we will make our periodic reports and other information filed with or furnished to the 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.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

QEP Resources, Inc. is subject to the information requirements of the Exchange Act, and in accordance therewith files reports and other information with the SEC. You may read QEP Resources, Inc.’s filings on the SEC’s website and at the public reference room described above. QEP Resources, Inc.’s common stock trades on the NYSE under the symbol “QEP.”

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

•

changes in general economic conditions;

•

competitive conditions in our industry;

•

actions taken by third-party operators, processors and transporters;

•

the demand for oil and natural gas storage and transportation services;

•

our ability to successfully implement our business plan;

•

our ability to complete internal growth projects on time and on budget;

•

the price and availability of debt and equity financing;

•

the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;

•

competition from the same and alternative energy sources;

•

energy efficiency and technology trends;

•

operating hazards and other risks incidental to transporting, storing and processing oil and natural gas, as applicable;

•

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•

interest rates;

•

labor relations;

•

large customer defaults;

•

change in availability and cost of capital;

•

changes in tax status;

•

the effect of existing and future laws and government regulations;

•

the effects of future litigation; and

•

certain factors discussed elsewhere in this prospectus.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities law.

211

INDEX TO FINANCIAL STATEMENTS


QEP Midstream Partners, LP Unaudited Pro Forma Combined Financial Statements:

Introduction			F-2

Unaudited Pro Forma Combined Statement of Income for the Three Months Ended March 31, 2013			F-4

Unaudited Pro Forma Combined Statement of Income for the Year Ended December 31, 2012			F-5

Unaudited Pro Forma Combined Balance Sheet as of March 31, 2013			F-6

Notes to the Unaudited Pro Forma Combined Financial Statements			F-7

QEP Midstream Partners, LP Predecessor Unaudited Combined Financial Statements:

Unaudited Combined Statements of Income for the Three Months Ended March 31, 2013 and 2012			F-10

Unaudited Combined Balance Sheets as of March 31, 2013 and December 31, 2012			F-11

Unaudited Combined Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012			F-12

Unaudited Combined Statements of Equity for the Three Months Ended March 31, 2013			F-13

Notes Accompanying the Unaudited Combined Financial Statements			F-14

QEP Midstream Partners, LP Predecessor Combined Financial Statements:

Report of Independent Registered Public Accounting Firm			F-19

Combined Statements of Income for the Years Ended December 31, 2012 and 2011			F-20

Combined Balance Sheets as of December 31, 2012 and 2011			F-21

Combined Statements of Cash Flows for the Years Ended December 31, 2012 and 2011			F-22

Combined Statements of Equity for the Years Ended December 31, 2012 and 2011			F-23

Notes Accompanying the Combined Financial Statements			F-24

QEP Midstream Partners, LP Historical Balance Sheet:

Report of Independent Registered Public Accounting Firm			F-33

Balance Sheet as of April 19, 2013			F-34

Note to Balance Sheet			F-35

F-1

Unaudited pro forma combined financial statements

INTRODUCTION

Set forth below are the unaudited pro forma combined balance sheet of QEP Midstream Partners, LP (“we”, “our” or the “Partnership”) as of March 31, 2013 and the unaudited pro forma combined statement of income of the Partnership for the year ended December 31, 2012 and the three months ended March 31, 2013. The pro forma combined financial data of the Partnership have been derived by adjusting the historical combined financial statements of our predecessor (our “Predecessor”). Our Predecessor consists of all of QEP’s gathering assets in the Green River, Uinta and Williston basins including a 100% interest in QEPM Gathering I, LLC and Rendezvous Pipeline Company, a 78% interest in Rendezvous Gas Services, L.L.C., a 50% equity interest in Three Rivers Gathering, L.L.C., a 38% equity interest in Uintah Basin Field Services, L.L.C. and 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). QEP Field Services will contribute all of these entities to the Partnership with the exception of its 100% interest in the gathering assets and operations in the Uinta Basin, its 38% equity interest in Uintah Basin Field Services, L.L.C. and general support equipment, which have been removed in the pro forma adjustments. In addition, we will record the contribution at historical cost, as it will be considered a reorganization of entities under common control.

The historical combined financial statements of our Predecessor are set forth elsewhere in this prospectus, and the pro forma combined financial data of the Partnership should be read in conjunction with, and are qualified in their entirety by reference to, such historical combined financial statements and the related notes contained therein. The pro forma adjustments are based on currently available information and certain estimates and assumptions, and actual results may differ from the pro forma adjustments. However, management believes that these estimates and assumptions provide a reasonable basis for presenting the significant effects of the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions and are properly applied in the pro forma combined financial data.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of the offering had taken place on March 31, 2013, in the case of the pro forma balance sheet, and as of January 1, 2012, in the case of the pro forma income statements for the year ended December 31, 2012 and the three months ended March 31, 2013. The pro forma combined financial data have been prepared on the assumption that we will be treated as a partnership for United States federal income tax purposes.

The unaudited pro forma financial data gives pro forma effect to the matters described in the notes hereto, including:

•

the contribution of (i) a 100% equity interest in QEPM Gathering I, LLC, (ii) a 100% equity interest in Rendezvous Pipeline Company, L.L.C., (iii) a 78% interest in Rendezvous Gas Services, L.L.C., and (iv) a 50% equity interest in Three Rivers Gathering, L.L.C.

•

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

•

our entry into a new $ million revolving credit facility, interest expense related to borrowings, the fees for the unused portion and the amortization of the deferred finance costs associated with the 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.”

F-2

The unaudited pro forma combined financial data do 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 unaudited pro forma combined financial data may not be indicative of the results that actually would have occurred if the Partnership had assumed the operations of our Predecessor on the dates indicated or that would be obtained in the future.

F-3

QEP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

For the Three Months Ended March 31, 2013


	Predecessor Historical			Predecessor Retained			Pro Forma Adjustments			Pro Forma
	(in millions, except per unit amounts)
Revenues
Gathering and transportation	$	36.6		$	(7.6	)(a)				$	29.0
Condensate sales		3.5			(1.5	)(a)					2.0

Total Revenues		40.1			(9.1	)		—			31.0

Operating expenses
Gathering		7.7			(1.9	)(a)					5.8
General and administrative		5.7			(1.4	)(a)		0.2	(c)		4.5
Taxes other than income taxes		0.3			(0.1	)(a)					0.2
Depreciation and amortization		10.3			(2.3	)(a)					7.7
					(0.3	)(b)

Total operating expenses		24.0			(6.0	)		0.2			18.2

Net loss from property sales		(0.3	)		0.3	(a)		—			—

Operating income		15.8			(2.8	)		(0.2	)		12.8

Income from unconsolidated affiliates		1.3			(0.7	)(a)					0.6
Interest (expense) income		(1.1	)		(0.2	)(a)		1.3	(d)		(0.9	)
								(0.9	)(e)

Net income		16.0			(3.7	)		0.2			12.5
Net income attributable to noncontrolling interest		(0.6	)		—	(a)		—			(0.6	)

Net income attributable to Predecessor	$	15.4		$	(3.7	)	$	0.2		$	11.9

General partner’s interest in net income attributable to QEP Midstream Partners, LP
Limited partner’s interest in net income attributable to QEP Midstream Partners, LP
Common units
Subordinated units
Net income per limited partner unit
Common units
Subordinated units
Weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

See notes accompanying the unaudited pro forma combined financial statements.

F-4

QEP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

Year Ended December 31, 2012


	Predecessor Historical			Predecessor Retained			Pro Forma Adjustments			Pro Forma
	(in millions, except per unit amounts)
Revenues
Gathering and transportation	$	151.3		$	(32.3	)(a)				$	119.0
Condensate sales		10.9			(2.4	)(a)					8.5

Total revenues		162.2			(34.7	)					127.5

Operating expenses
Gathering expense		29.9			(8.8	)(a)					21.1
General and administrative		17.0			(4.8	)(a)		3.0	(c)		15.2
Taxes other than income taxes		3.1			(1.0	)(a)					2.1
Depreciation and amortization		39.8			(9.2	)(a)					29.9
					(0.7	)(b)

Total operating expenses		89.8			(24.5	)		3.0			68.3

Operating income		72.4			(10.2	)		(3.0	)		59.2

Other income		0.1			—	(a)					0.1
Income from unconsolidated affiliates		7.2			(3.7	)(a)					3.5
Interest (expense) income		(8.7	)		(1.0	)(a)		9.7	(d)		(3.5	)
								(3.5	)(e)

Net income		71.0			(14.9	)		3.2			59.3
Net income attributable to noncontrolling interest		(3.7	)		—	(a)		—			(3.7	)

Net income attributable to our Predecessor or us	$	67.3		$	(14.9	)	$	3.2		$	55.6

General partner’s interest in net income attributable to QEP Midstream Partners, LP
Limited partner’s interest in net income attributable to QEP Midstream Partners, LP
Common units
Subordinated units
Net income per limited partner unit
Common units
Subordinated units
Weighted average number of limited partner units outstanding (basic and diluted)
Common units
Subordinated units

See notes accompanying the unaudited pro forma combined financial statements.

F-5

QEP MIDSTREAM PARTNERS, LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

As of March 31, 2013


	Predecessor Historical		Predecessor Retained			Pro Forma Adjustments			Pro Forma
		(in millions, except per unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	2.9	$	—	(a)	$	350.0	(f)	$	2.9
							(114.0	)(g)
							(208.9	)(j)
							(27.1	)(h)
Accounts receivable, net		19.3		(4.4	)(a)		—			14.9
Accounts receivable from related party		20.0		(2.3	)(a)		—			17.7
Natural gas imbalance receivable		1.8		(0.4	)(a)		—			1.4
Other current assets		0.1		—	(a)		(0.1	)(h)		—

Total current assets		44.1		(7.1	)		(0.1	)		36.9

Property, plant and equipment, net		625.2		(128.1	)(a)					493.1
				(4.0	)(b)
Investment in unconsolidated affiliates		40.5		(11.8	)(a)		—			28.7
Account receivable, noncurrent		—		—	(a)		—			—

Total assets	$	709.8	$	(151.0	)	$	(0.1	)	$	558.7

LIABILITIES
Current liabilities:
Accounts payable	$	4.4	$	(1.1	)(a)	$	(0.1	)(h)	$	3.2
Accounts payable from related party		7.3		(2.2	)(a)		—			5.1
Natural gas imbalance liability		1.8		(0.4	)(a)		—			1.4
Deferred revenue		5.8		—	(a)		—			5.8
Accrued compensation		1.1		(0.3	)(a)		—			0.8
Other current liabilities		1.3		(0.4	)(a)		—			0.9

Total current liabilities		21.7		(4.4	)		(0.1	)(h)		17.2

Long-term debt to related party		85.7		28.3	(a)		(114.0	)(g)		—
Asset retirement obligation		16.6		(5.1	)(a)		—			11.5
Deferred revenue		6.5		—	(a)		—			6.5

Total long-term liabilities		108.8		23.2			(114.0	)		18.0

EQUITY AND PARTNERS’ CAPITAL
Parent net investment		532.5		(165.8	)(a)		(153.8	)(i)		—
				(4.0	)(b)		(208.9	)(j)

Common unitholders — public		—		—			350.0	(f)		322.9
							(27.1)	(h)
Common units, subordinated units and general partner interest — QEP		—		—			153.8	(i)		153.8

Total Partners’ Capital/Parent Net Equity		532.5		(169.8	)		114.0			476.7
Noncontrolling interest		46.8		—	(a)		—			46.8

Total equity/partners’ capital		579.3		(169.8	)		114.0			523.5

Total liabilities and equity/partners’ capital	$	709.8	$	(151.0	)	$	(0.1	)	$	558.7

See notes accompanying the unaudited pro forma combined financial statements.

F-6

QEP MIDSTREAM PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1.	BASIS OF PRESENTATION, OTHER TRANSACTIONS AND THE OFFERING

The unaudited pro forma combined statement of income of QEP Midstream Partners, LP (the “Partnership,” “our,” “us” or “we”) for the year ended December 31, 2012 and for the three months ended March 31, 2013 and the unaudited pro forma combined balance sheet as of March 31, 2013 are based upon the audited historical combined financial statements of QEP Midstream Partners Predecessor (the “Predecessor”), which consists of all of QEP Resources, Inc.’s (“QEP”) gathering assets in the Green River, Uinta and Williston basins including a 100% interest in QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C., a 78% interest in Rendezvous Gas Services, L.L.C., a 50% equity interest in Three Rivers Gathering, L.L.C., and a 38% equity interest in Uintah Basin Field Services, L.L.C. and a 100% interest in all other gathering assets and operations of QEP in the Uinta Basin (collectively referred to as Uinta Basin Gathering System).

Upon completion of this offering, the Partnership anticipates incurring incremental general and administrative expense of approximately $2.5 million per year as a result of being a publicly traded partnership, including 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 New York Stock Exchange; independent auditor fees; investor relations expenses; and registrar and transfer agent fees. The unaudited pro forma combined financial statements do not reflect these additional public company costs.

In addition, while other general and administrative expenses have not yet been determined, the Partnership intends to enter into an omnibus agreement with QEP pursuant to which reimbursement of general and administrative expenses by the Partnership to QEP will be capped at $ million annually through December 31, , subject to increases. The $ million cap does not apply to any reimbursement by the Partnership to QEP for additional public company costs.

2.	Predecessor Retained Adjustments

(a) Reflects the retention of the Uinta Basin Gathering System.

(b) Reflects the retention of general support equipment by QEP. As part of our omnibus agreement QEP will charge us a fee for general support equipment, which is reflected in the pro forma adjustment to general and administrative expenses.

3.	Pro forma Adjustments

The following adjustments for the Partnership have been prepared as if the Partnership’s initial public offering and related transactions had taken place at January 1, 2012 in the case of the pro forma income statement and on March 31, 2013 in the case of the pro forma balance sheet.

(c) Reflects the estimated adjustment for incremental general and administrative expenses as a result of the entry into an omnibus agreement. The omnibus agreement will provide for direct charges for the operation of the Partnership’s assets and other administrative services costs allocated to us by QEP, based on several factors, including our proportionate share of QEP’s property, plant and equipment, operating income and direct labor costs.

(d) Reflects the elimination of historical interest expense due to the repayment of the related party long-term debt with QEP.

(e) Reflects the estimated amortization of the deferred finance costs related to the revolving credit facility, estimated interest expense related to borrowings under the revolving credit facility and estimated fees on the unused portion of the revolving credit facility. We assume our commitment fee on any undrawn portion of our credit facility will be comparable to similar midstream master limited partnerships.

F-7

(f) Reflects the assumed gross offering proceeds to the Partnership of $350.0 million from the issuance and sale of common units at an assumed initial public offering price of $ per unit. If the underwriters were to exercise their option to purchase additional common units in full, gross proceeds to the Partnership would equal $400 million. The Partnership will use the proceeds from the sale of additional common units to the underwriters pursuant to their option to redeem an equivalent number of units from QEP.

(g) Reflects a portion of the offering proceeds used to repay the long-term debt balance with QEP of $114.0 million.

(h) Reflects the estimated payment of underwriting discounts, structuring fees, estimated offering expenses, legal services, transaction consulting services, auditor fees, filing and printing fees, and exchange listing fees of $27.1 million, all of which will be allocated to public common units.

(i) Reflects the conversion of adjusted parent net investment of $153.8 million to common, subordinated and general partner capital of the Partnership.

(j) Reflects a cash distribution to QEP of $208.9 million, a portion of which will be used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to us.

After the conversion, the equity amounts of the common and subordinated units will be % and %, respectively, with the remaining 2% representing the general partner interest.

4.	Pro Forma Net Income Per Limited Partner Unit

Pro forma net income per limited partner unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that the minimum quarterly distribution was made to all unitholders during the period presented.

Pro forma QEP Midstream Partners, LP earnings per unit was calculated using common and subordinated units. The common and subordinated units represented an aggregate 100% limited partner interest in QEP Midstream Partners, LP. All units were assumed to have been outstanding since January 1, 2012.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit.

Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being

F-8

allocated to our general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to our general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the periods.

F-9

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

UNAUDITED COMBINED STATEMENTS OF INCOME


	Three Months Ended March 31,
	2013			2012
	(in millions)
Revenues
Gathering and transportation	$	36.6		$	36.9
Condensate sales		3.5			5.0

Total Revenues		40.1			41.9

Operating expenses
Gathering		7.7			7.2
General and administrative		5.7			3.6
Taxes other than income taxes		0.3			0.8
Depreciation and amortization		10.3			9.8

Total Operating Expenses		24.0			21.4

Net loss from property sales		(0.3	)		—

Operating Income		15.8			20.5
Income from unconsolidated affiliates		1.3			1.9
Interest expense		(1.1	)		(1.8	)

Net income		16.0			20.6
Net income attributable to noncontrolling interest		(0.6	)		(0.8	)

Net income attributable to Predecessor	$	15.4		$	19.8

Pro forma basic earnings per common unit (Note 2)
Pro forma diluted earnings per common unit (Note 2)

See notes accompanying the combined financial statements.

F-10

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

UNAUDITED COMBINED BALANCE SHEETS


	Supplemental Unaudited Pro Forma March 31, 2013		Predecessor
	Supplemental Unaudited Pro Forma March 31, 2013		March 31, 2013		December 31, 2012
			(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	2.9	$	2.9	$	1.4
Accounts receivable, net		19.3		19.3		18.2
Accounts receivable from related party		20.0		20.0		24.9
Natural gas imbalance receivable		1.8		1.8		2.2
Other current assets		0.1		0.1		0.1

Total current assets		44.1		44.1		46.8

Property, plant and equipment, net		625.2		625.2		634.1
Investment in unconsolidated affiliates		40.5		40.5		40.7
Accounts receivable, noncurrent		—		—		3.8

Total assets	$	709.8	$	709.8	$	725.4

LIABILITIES
Current liabilities:
Accounts payable	$	4.4	$	4.4	$	6.3
Accounts payable to related party		7.3		7.3		3.7
Distribution payable to QEP		208.9		—		—
Natural gas imbalance liability		1.8		1.8		2.2
Deferred revenue		5.8		5.8		0.3
Accrued compensation		1.1		1.1		1.7
Other current liabilities		1.3		1.3		1.3

Total current liabilities		230.6		21.7		15.5

Long-term debt to related party		85.7		85.7		131.1
Asset retirement obligation		16.6		16.6		16.3
Deferred revenue		6.5		6.5		10.2

Total long-term liabilities		108.8		108.8		157.6

Commitments and contingencies (see Note 6)

EQUITY
Parent net investment		323.6		532.5		504.6
Noncontrolling interest		46.8		46.8		47.7

Total net equity		370.4		579.3		552.3

Total liabilities and equity	$	709.8	$	709.8	$	725.4

See notes accompanying the combined financial statements.

F-11

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

UNAUDITED COMBINED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2013			2012
	(in millions)
OPERATING ACTIVITIES
Net income	$	16.0		$	20.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10.3			9.8
Income from unconsolidated affiliates		(1.3	)		(1.9	)
Distributions from unconsolidated affiliates		1.5			1.5
Net loss from asset sales		0.3			—
Changes in operating assets and liabilities:
Accounts receivable		9.1			6.6
Accounts payable and accrued expenses		2.6			(3.7	)
Other		0.4			3.7

Net cash provided by operating activities		38.9			36.6

INVESTING ACTIVITIES
Property, plant and equipment		(3.9	)		(11.8	)
Proceeds from sale of assets		0.8			—

Net cash used in investing activities		(3.1	)		(11.8	)

FINANCING ACTIVITIES
Repayments of long-term debt to related party		(45.3	)		(15.1	)
Contributions from (distributions to) parent, net		12.5			(7.5	)
Distribution to noncontrolling interest		(1.5	)		(1.7	)

Net cash used in financing activities		(34.3	)		(24.3	)

Change in cash and cash equivalents		1.5			0.5
Beginning cash and cash equivalents		1.4			2.5
Ending cash and cash equivalents	$	2.9		$	3.0

Supplemental Disclosures:
Non-cash investing activities
Change in capital expenditure accrual balance	$	(1.7	)	$	(1.0	)

See notes accompanying the combined financial statements.

F-12

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

UNAUDITED COMBINED STATEMENTS OF EQUITY


	Parent Net Investment			Noncontrolling Interest			Total net equity
Balance at December 31, 2011	$	451.8		$	50.6		$	502.4
Q1 2012 net income		19.8			0.8			20.6
Contributions from (distributions to) parent, net		(7.5	)		—			(7.5	)
Distribution of noncontrolling interest		—			(1.7	)		(1.7	)

Balance at March 31, 2012	$	464.1		$	49.7		$	513.8


Balance at December 31, 2012	$	504.6		$	47.7		$	552.3
Q1 2013 net income		15.4			0.6			16.0
Contributions from (distributions to) parent, net		12.5			—			12.5
Distribution of noncontrolling interest		—			(1.5	)		(1.5	)

Balance at March 31, 2013	$	532.5		$	46.8		$	579.3

See notes accompanying the combined financial statements.

F-13

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

NOTES ACCOMPANYING THE UNAUDITED COMBINED FINANCIAL STATEMENTS

Note

1 — Description of Business and Basis of Presentation

These financial statements of QEP Midstream Partners, LP Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering of common units representing limited partner interests (the “Offering”) in QEP Midstream Partners, LP (the “Partnership”, “we, or “our”), which was formed in Delaware on April 19, 2013 and is expected to own the operations and assets of the Predecessor upon closing. Our Predecessor consists of all of QEP’s gathering assets in the Green River, Uinta and Williston basins including a 100% interest in QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C., a 78% interest in Rendezvous Gas Services, L.L.C., a 50% equity interest in Three Rivers Gathering, L.L.C., a 38% equity interest in Uintah Basin Field Services, L.L.C. and a 100% interest in all other gathering assets and operations of QEP in the Uinta Basin (collectively referred to as Uinta Basin Gathering System). For purposes of these financial statements, “QEP” refers to QEP Resources, Inc. and its consolidated subsidiaries.

The Predecessor’s 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 in Colorado, North Dakota, Utah and Wyoming. As part of the Offering, QEP Midstream Partners, GP, LLC (“GP”) and QEP Field Services, both QEP affiliates, will collectively contribute to the Partnership (i) a 100% ownership interest in each of QEP Midstream Partners Operating, LLC, QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C., (ii) a 78% interest in Rendezvous Gas Services, L.L.C., and (iii) a 50% equity interest in Three Rivers Gathering, L.L.C (collectively, the “Contributed Assets”). GP will serve as the general partner of the Partnership and together with QEP will provide services to the Partnership pursuant to an omnibus agreement and a service agreement between the parties.

Interim combined financial statements do not include all of the information and notes required by accounting principles generally accepted in the United States (GAAP) for audited combined financial statements. These financial statements should be read in conjunction with the Predecessor’s combined financial statements for the year ended December 31, 2012. These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the Predecessor’s results of operations and financial position. Amounts reported in the combined statement of operations are not necessarily indicative of amounts expected for the respective annual periods.

The unaudited combined financial statements of the Predecessor have been prepared in accordance with GAAP on the basis of QEP’s historical ownership of the Predecessor assets. These combined financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner’s equity, in the unaudited combined financial statements.

The Predecessor’s costs of doing business incurred by QEP on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses charged as a management services fee by QEP to the Predecessor in exchange for:

•

business services, such as payroll, accounts payable and facilities management;

•

corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;

•

executive compensation, including share-based compensation; and

•

pension and other post-retirement benefit costs.

Transactions between the Predecessor and QEP have been identified in the combined financial statements as transactions between affiliates (see Note 3).

F-14

Note

2 — Summary of Significant Accounting Policies

Investment in Unconsolidated Affiliates

The Predecessor uses the equity method to account for investment in unconsolidated affiliates. The investment in unconsolidated affiliates on the Predecessor’s combined balance sheets equals the Predecessor’s proportionate share of equity reported by the unconsolidated affiliates. Investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.

The principal unconsolidated affiliates and the ownership percentage as of March 31, 2013 and December 31, 2012, were Uintah Basin Field Services, LLC (38%) and Three Rivers Gathering, LLC (50%), both limited liability companies engaged in the gathering and compression of natural gas.

Noncontrolling Interests

The Predecessor has a 78% interest in Rendezvous Gas Services, LLC, a partnership with Western Gas Partners, LP that owns a gas gathering system. The Predecessor consolidates Rendezvous Gas Services under the voting interest model. The Predecessor’s non-controlling interest is presented on the Unaudited Combined Income Statement and Unaudited Combined Balance Sheet accordingly.

Supplemental Pro Forma Information

Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of the proposed initial public offering of QEP Midstream Partners, LP, the Partnership estimates that it will distribute approximately $208.9 million in cash to QEP. As part of the initial public offering, QEP will own, on behalf of its members, the equity interests in the Partnership’s general partner as well as common and subordinated units of the Partnership. The supplemental pro forma balance sheet as of March 31, 2013 gives pro forma effect to these assumed distributions as though they had been declared and were payable as of that date.

Unaudited pro forma basic and diluted earnings per common unit assumes subordinated units and common units were outstanding for the three months ended March 31, 2013. The unaudited pro forma basic and diluted earnings per common unit for the Partnership for the three months ended March 31, 2013 has been calculated using an assumed capital structure of the Partnership consisting of general partner units, subordinated units and common units.

Use of Estimates

The preparation of the combined financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the carrying amount of property, plant and equipment, valuation allowances for receivables, valuation of accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Credit Risk

Exposure to credit risk may be affected by the concentration of customers due to changes in economic or other conditions. Customers include individuals and commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

F-15

The customers accounting for 10% or more of the Predecessor’s combined revenues for the three months ended March 31, 2013 and 2012 are as follows:


	Three Months Ended March 31,
	2013			2012
QEP		52	%		44	%
Questar Gas Company		11	%		14	%
EOG Resources Inc.		9	%		11	%

The Predecessor’s principal customer for natural gas gathering, compression, treating and transportation services is QEP. Except for those customers listed above, no other single customer accounted for greater than 10% of revenue during the three months ended March 31, 2013 and 2012. Management believes that the risk of loss of a large customer is remote as a result of its contractual obligations.

Recent Accounting Developments

In December of 2011, the FASB issued ASU 2011-11, Disclosures about Offsetting Assets and Liabilities, which enhances disclosure requirements regarding an entity’s financial instruments and derivative instruments that are offset or subject to a master netting arrangement. This information about offsetting and related netting arrangements will enable users of financial statements to understand the effect of those arrangements on the entity’s financial position, including the effect of rights of setoff. The amendments were required for annual reporting periods beginning after January 1, 2013, and interim periods within those annual periods. The adoption of this ASU did not have a material effect on our disclosure requirements.

Note

3 — Related Party Transactions

The Predecessor provides natural gas gathering, compression, treating and transportation services to QEP resulting in affiliate transactions. The Predecessor’s revenues and expenses with QEP result in affiliate transactions.

Centralized cash management

QEP operates a cash management system whereby excess cash from its various subsidiaries, held in separate bank accounts, is swept to a centralized account. Sales and purchases related to third-party transactions are settled in cash but are received or paid by QEP within the centralized cash management system.

Affiliated debt

During the first quarter of 2012, QEP Field Services had a $250.0 million revolving debt agreement (2011 Agreement) with QEP for its funding shortfalls, in which QEP Field Services was charged a variable interest rate. Interest during the first quarter of 2012 was allocated to the Predecessor based on an interest rate equal to QEP’s average borrowing rate, which was 5.2% in the first quarter of 2012. In April 2012, the Predecessor entered into new debt agreements with QEP replacing the 2011 Agreement with a $250 million promissory note that matures in March 2013. The promissory note was renewed in March 2013 with a maturity date of March 2014. In addition, QEP Field Services entered into a $1 billion “revolving credit” type promissory note to fund capital expenditures that matures in March 2017. QEP Field Services has the ability and intent to refinance the promissory note on a long-term basis under the $1.0 billion promissory note. Accordingly, all amounts have been classified as “Long-term debt to related party” in our Combined Balance Sheets. Both agreements require QEP Field Services to pay QEP interest during the first quarter of 2013 at a 6.05% fixed-rate. Interest allocated to the Predecessor under these notes in the first quarter of

F-16

2013 was based on the fixed-rate due to QEP. QEP Field Services was compliant with its covenants under the agreement at March 31, 2013 and there are no letters of credit outstanding. At March 31, 2013 and December 31, 2012, allocated debt outstanding for the Predecessor was $85.7 million and $131.1 million, respectively.

Allocation of costs

The employees supporting the Predecessor’s operations are employees of QEP. General and administrative expense allocated to our Predecessor was $5.7 million and $3.6 million for the three months ended March 31, 2013 and March 31, 2012, respectively. The combined financial statements of the Predecessor include direct charges for operations of our assets and costs allocated by QEP. These costs are reimbursed and relate to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) restructuring, compensation, share-based compensation, and pension and post-retirement costs. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and its proportionate share of QEP’s gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies are reasonable.

The following table summarizes the related party income statement transactions with QEP:


	Three Months Ended March 31,
	2013			2012
	(in millions)
Revenues from affiliate	$	20.7		$	18.4
Interest expense to affiliate		(1.1	)		(1.8	)

Note

4 — Property, Plant and Equipment

A summary of the historical cost of the Predecessor’s property, plant and equipment is as follows:


	Estimated useful lives
	Estimated useful lives		March 31, 2013			December 31, 2012
			(in millions)
Gathering equipment		5 to 40 years	$	908.0		$	907.7
General support equipment		3 to 30 years		11.5			11.1

Total property, plant and equipment				919.5			918.8
Accumulated depreciation				(294.3	)		(284.7	)

Total net property, plant and equipment			$	625.2		$	634.1

Note

5 — Asset Retirement Obligations

The Predecessor records ARO when there are legal obligations associated with the retirement of tangible long-lived assets. The fair values of such costs are estimated by Predecessor personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO liability may occur, amongst other things, due to changes in estimated abandonment costs and estimated settlement timing. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted, risk-free interest rate of the Predecessor.

F-17

The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:


	Asset Retirement Obligations
	2013
	(in millions)
ARO liability at January 1,	$	16.3
Accretion		0.3

ARO liability at March 31,	$	16.6

Note

6 — Commitments and Contingencies

The Predecessor is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Predecessor assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its combined financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Predecessor may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Predecessor’s litigation loss contingencies are discussed below. The Predecessor is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. The Predecessor believes, however, that the resolution of pending proceedings will not have a material effect on the Predecessor’s financial position, results of operations or cash flows.

Litigation

Our gathering systems are the subject of ongoing litigation between Questar Gas Company (QGC) and QEP Field Services Company, Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate, QGC, filed this 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) executed when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services to QGC. 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 Field Services. As of March 31, 2013, our Predecessor has deferred revenue of $4.9 million 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 a declaratory judgment relating to its gathering services under the same agreement. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

F-18

QEP Midstream Partners, LP Predecessor

Report of Independent Registered Public Accounting Firm

To the Board of Directors of QEP Resources, Inc:

In our opinion, the accompanying combined balance sheets and the related combined statements of income, equity, and cash flows present fairly, in all material respects, the financial position of QEP Midstream Partners, LP Predecessor at December 31, 2012 and December 31, 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

May 9, 2013, except for Note 3, as to which the date is July 3, 2013.

F-19

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF INCOME


	Year Ended December 31,
	2012			2011
	(in millions)
Revenues
Gathering and transportation	$	151.3		$	140.4
Condensate sales		10.9			15.5

Total revenues		162.2			155.9

Operating expenses
Gathering expense		29.9			27.7
General and administrative		17.0			15.3
Taxes other than income taxes		3.1			2.8
Depreciation and amortization		39.8			38.3

Total operating expenses		89.8			84.1

Operating income		72.4			71.8
Other income		0.1			0.1
Income from unconsolidated affiliates		7.2			4.4
Interest expense		(8.7	)		(12.8	)

Net income		71.0			63.5
Net income attributable to noncontrolling interest		(3.7	)		(3.2	)

Net income attributable to Predecessor	$	67.3		$	60.3

Unaudited pro forma basic earnings per common unit (Note 2)
Unaudited pro forma diluted earnings per common unit (Note 2)

See notes accompanying the combined financial statements.

F-20

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED BALANCE SHEETS


	Supplemental Unaudited Pro Forma December 31, 2012		Predecessor
	Supplemental Unaudited Pro Forma December 31, 2012		December 31, 2012		December 31, 2011
			(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1.4	$	1.4	$	2.5
Accounts receivable, net		18.2		18.2		16.8
Accounts receivable from related party		24.9		24.9		18.2
Natural gas imbalance receivable		2.2		2.2		4.3
Other current assets		0.1		0.1		—

Total current assets		46.8		46.8		41.8

Property, plant and equipment, net		634.1		634.1		629.1
Investment in unconsolidated affiliates		40.7		40.7		41.2
Accounts receivable, noncurrent		3.8		3.8		—
Account receivable from related party, noncurrent		—		—		2.2

Total assets	$	725.4	$	725.4	$	714.3

LIABILITIES
Current liabilities:
Accounts payable	$	6.3	$	6.3	$	7.7
Accounts payable to related party		3.7		3.7		4.9
Distribution payable to QEP		175.4		—		—
Natural gas imbalance liability		2.2		2.2		4.3
Environmental contingency		—		—		4.0
Accrued compensation		1.7		1.7		1.9
Other current liabilities		1.6		1.6		0.9

Total current liabilities		190.9		15.5		23.7

Long-term debt to related party		131.1		131.1		174.6
Asset retirement obligation		16.3		16.3		13.6
Deferred revenue		10.2		10.2		—

Total long-term liabilities		157.6		157.6		188.2

Commitments and contingencies (see Note 7)

EQUITY
Parent net investment		329.2		504.6		451.8
Noncontrolling interest		47.7		47.7		50.6

Total net equity		376.9		552.3		502.4

Total liabilities and equity	$	725.4	$	725.4	$	714.3

See notes accompanying the combined financial statements.

F-21

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2012			2011
	(in millions)
OPERATING ACTIVITIES
Net income	$	71.0		$	63.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		39.8			38.3
Income from unconsolidated affiliates		(7.2	)		(4.4	)
Distributions from unconsolidated affiliates		7.8			7.7
Changes in operating assets and liabilities:
Accounts receivable		(2.4	)		(8.4	)
Accounts payable and accrued expenses		(1.6	)		0.9
Other		(0.4	)		(0.1	)

Net cash provided by operating activities		107.0			97.5

INVESTING ACTIVITIES
Property, plant and equipment		(43.7	)		(28.6	)
Proceeds from sale of assets		0.3			0.1

Net cash used in investing activities		(43.4	)		(28.5	)

FINANCING ACTIVITIES
Repayments of long-term debt to related party		(43.6	)		(63.6	)
Contributions from (distributions to) parent, net		(14.5	)		1.0
Distribution to noncontrolling interest		(6.6	)		(5.4	)

Net cash used in financing activities		(64.7	)		(68.0	)

Change in cash and cash equivalents		(1.1	)		1.0
Beginning cash and cash equivalents		2.5			1.5
Ending cash and cash equivalents	$	1.4		$	2.5
Supplemental Disclosures:
Non-cash investing activities
Change in capital expenditure accrual balance	$	(1.3	)	$	(1.5	)

See notes accompanying the combined financial statements.

F-22

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF EQUITY


	Parent Net Investment			Noncontrolling Interest			Total net equity
Balance at December 31, 2010	$	390.5		$	52.8		$	443.3
2011 net income		60.3			3.2			63.5
Contributions from (distributions to) parent, net		1.0			—			1.0
Distribution of noncontrolling interest		—			(5.4	)		(5.4	)

Balance at December 31, 2011	$	451.8		$	50.6		$	502.4

2012 net income		67.3			3.7			71.0
Contributions from (distributions to) parent, net		(14.5	)		—			(14.5	)
Distribution of noncontrolling interest		—			(6.6	)		(6.6	)

Balance at December 31, 2012	$	504.6		$	47.7		$	552.3

See notes accompanying the combined financial statements.

F-23

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

NOTES ACCOMPANYING THE COMBINED FINANCIAL STATEMENTS

Note

1 — Description of Business and Basis of Presentation

The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States (GAAP) on the basis of QEP’s historical ownership of the Predecessor assets. These combined financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner’s equity, in the combined financial statements. Further, the combined financial statements of the Predecessor include only two years of audited financial statements as we qualify as an emerging growth company.

•

business services, such as payroll, accounts payable and facilities management;

•

corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;

•

executive compensation, including share-based compensation; and

•

pension and other post-retirement benefit costs.

Transactions between the Predecessor and QEP have been identified in the combined financial statements as transactions between affiliates (see Note 4).

F-24

Note

2 — Summary of Significant Accounting Policies

Revenue Recognition

The Predecessor provides natural gas gathering and transportation services, primarily under fee-based contracts. Under these arrangements, the Predecessor receives a fee or fees for one or more of the following services: firm and interruptible gathering or transmission of natural gas, crude oil, condensate, and water. The revenue the Predecessor earns from these arrangements is generally directly related to the volume of natural gas, crude oil, or water that flows through the Predecessor’s systems and is not directly dependent on commodity prices. Revenue for these agreements is recognized at the time the service is performed. In certain of these contracts, the Predecessor’s agreement provides for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms. In addition, under certain of these gathering agreements, the Predecessor retains and sells condensate, which falls out of the natural gas stream during the gathering process. The Predecessor recognizes revenue from condensate sales upon transfer of title. The Predecessor has deferred revenue of which a portion will be recognized as revenue pursuant to contractual terms with the remaining being recognized based on the outcome of certain litigation (see Note 7).

Investment in Unconsolidated Affiliates

The principal unconsolidated affiliates and the ownership percentage as of December 31, 2012 and 2011, were Uintah Basin Field Services, L.L.C. (38%) and Three Rivers Gathering, L.L.C. (50%), both limited liability companies engaged in the gathering and compression of natural gas.

Noncontrolling Interests

The Predecessor has a 78% interest in Rendezvous Gas Services, L.L.C., a partnership with Western Gas Partners, LP that owns a gas gathering system. The Predecessor consolidates Rendezvous Gas Services, L.L.C. under the voting interest model. The Predecessor’s non-controlling interest is presented on the Combined Income Statement and Combined Balance Sheet accordingly.

Supplemental Pro Forma Information (Unaudited)

Staff Accounting Bulletin 1.B.3 requires that certain distributions to owners prior to or concurrent with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of the proposed initial public offering of QEP Midstream Partners, LP, the Partnership estimates that it will distribute approximately $175.4 million in cash to QEP. As part of the initial public offering, QEP will own, on behalf of its members, the equity interests in the Partnership’s general partner as well as common and subordinated units of the Partnership. The supplemental pro forma balance sheet as of December 31, 2012 gives pro forma effect to these assumed distributions as though they had been declared and were payable as of that date.

Unaudited pro forma basic and diluted earnings per common unit, assumes subordinated units and common units were outstanding for the year ended December 31, 2012. The unaudited pro forma basic and diluted earnings per common unit for the Partnership for the year ended December 31, 2012 has been calculated using an assumed capital structure of the Partnership consisting of general partner units, subordinated units and common units.

F-25

Use of Estimates

Cash and Cash Equivalents

The majority of the Predecessor’s operations are funded by QEP and managed under QEP’s centralized cash management program. Cash equivalents consist principally of repurchase agreements with maturities of three months or less. The repurchase agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in available funds the next business day.

Accounts Receivable Trade

The Predecessor’s receivables consist of third party and QEP invoices. The Predecessor routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The Predecessor’s allowance for bad-debt expense was $0.4 million and $0.3 million at December 31, 2012 and 2011, respectively.

Property, Plant and Equipment

Impairment of Long-Lived Assets

The Predecessor evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset or a change in management’s intent to utilize the asset.

There were no long-lived asset impairments recognized during 2012 and 2011.

Asset Retirement Obligations

Asset retirement obligations (ARO) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Predecessor’s credit-adjusted, risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

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Natural Gas Imbalances

The combined balance sheets include natural gas imbalance receivables or payables resulting from differences in gas volumes received and gas volumes delivered to customers. Natural gas volumes owed to or by the Predecessor that are subject to tariffs are valued at market index prices, as of the balance sheet dates, and are subject to cash settlement procedures. Other natural gas volumes owed to or by the Predecessor are valued at the Predecessor’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.

Litigation and Other Contingencies

In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Predecessor regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. See Note 7 — Commitments and Contingencies, for additional information.

The Predecessor accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable.

Credit Risk

The customers accounting for 10% or more of the Predecessor’s combined revenues for the years ended December 31, 2012 and 2011 are as follows:


	Year Ended December 31,
	2012			2011
QEP		49	%		45	%
Questar Gas Company		12	%		16	%
EOG Resources Inc.		11	%		13	%

The Predecessor’s principal customer for natural gas gathering, compression, treating and transportation services is QEP. Except for those customers listed above, no other single customer accounted for greater than 10% of revenue during 2012 and 2011. Management believes that the risk of loss of a large customer is remote as a result of its contractual obligations.

Fair Value Measurements

The Predecessor did not have any assets accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. We believe the carrying values of our current assets and liabilities approximate fair value. The carrying amount of our affiliated long-term debt approximates fair value.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs are used in the calculation of asset retirement obligations include retirement costs and asset lives. A reconciliation of the Partnership’s asset retirement obligations is presented in Note 5 — Asset Retirement Obligations.

F-27

Post-Retirement Employee Benefit Plans

The Predecessor is allocated a portion of the expense associated in the various employee benefit plans of QEP. These plans included a qualified defined benefit pension plan, a nonqualified, unfunded, defined pension plan, post-retiree medical plans, and an employee investment plan. For purposes of these combined financial statements, the Predecessor is considered to be participating in the employee benefit plans of QEP. As a participant in the benefit plans, the Predecessor recognizes as expense in each period the allocation from QEP, and it does not recognize any employee benefit plan liabilities.

Share-Based Compensation

The Predecessor’s financial statements reflect various share-based compensation awards by QEP. These awards include stock options, restricted shares and performance share units. For purposes of these combined financial statements, the Predecessor recognized as expense in each period the required allocation from QEP, with the offset included in net parent equity.

Income Taxes

The Predecessor’s financial statements do not include income tax allocation as we expect that the Partnership will be treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income.

Recent Accounting Developments

Note

3 — Revisions

Subsequent to issuing the December 31, 2012 financial statements, the Predecessor identified errors in our general and administrative expense allocation and condensate sales for the year ended December 31, 2012. Because of the methodology used to allocate long-term debt, these errors also impacted the allocated long-term debt balance as of December 31, 2012. The Predecessor assessed the materiality of these errors and concluded they were not material to the 2012 annual period, however, the Predecessor has determined that correction of the errors would be preferable. The Predecessor has revised its combined financial statements as of and for the fiscal year ended December 31, 2012. The following tables, in millions, present the impact on each financial statement of QEP Midstream Partners, LP Predecessor as of and for the year ended December 31, 2012:

Combined Statement of Income


	As reported		As revised		Change
Condensate sales	$	10.1	$	10.9	$	0.8
Total revenues		161.4		162.2		0.8
General and administrative expense		19.4		17.0		(2.4	)
Operating income		69.2		72.4		3.2
Net income		67.8		71.0		3.2
Net income attributable to Predecessor		64.1		67.3		3.2

F-28

Combined Balance Sheet


	As reported		As revised		Change
Accounts receivable from related party	$	24.1	$	24.9	$	0.8
Long-term debt to related party		134.2		131.1		(3.1	)
Parent net investment		500.7		504.6		3.9

Combined Statement of Cash Flow


	As reported			As revised			Change
Net cash provided by operating activities	$	104.5		$	107.0		$	2.5
Net cash used in financing activities		(62.2	)		(64.7	)		(2.5	)

Note

4 — Related Party Transactions

The Predecessor provides natural gas gathering, compression, treating and transportation services to QEP resulting in affiliate transactions. The following discussion describes these affiliate transactions in more detail.

Centralized Cash Management

Affiliated Debt

In 2011, QEP Field Services had a $250.0 million revolving debt agreement (2011 Agreement) with QEP for its funding shortfalls, in which QEP Field Services was charged a variable interest rate. Interest in 2011 and a portion of 2012 was allocated to the Predecessor based on an interest rate equal to QEP’s average borrowing rate, which was 5.9% in 2011. In April 2012, the Predecessor entered into new debt agreements with QEP replacing the 2011 Agreement with a $250 million promissory note that matures in March 2013. The promissory note was renewed in March 2013 with a maturity date of March 2014. In addition, QEP Field Services entered into a $1.0 billion “revolving credit” type promissory note to fund capital expenditures that matures in March 2017. QEP Field Services has the ability and intent to refinance the promissory note on a long-term basis under the $1.0 billion promissory note. Accordingly, all amounts have been classified as “Long-term debt to related party” in our Combined Balance Sheets. Both agreements required QEP Field Services to pay QEP interest at a 6.05% fixed-rate in 2012. Interest allocated to the Predecessor under these notes in 2012 was based on the fixed-rate due to QEP. QEP Field Services was compliant with its covenants under the agreement at December 31, 2012 and there are no letters of credit outstanding. At December 31, 2012 and 2011, allocated debt outstanding for the Predecessor was $131.1 million and $174.6 million, respectively.

Allocation of Costs

The employees supporting the Predecessor’s operations are employees of QEP. General and administrative expense allocated to our Predecessor was $17.0 million and $15.3 million for the years ended December 31, 2012 and 2011, respectively. The combined financial statements of the Predecessor include direct charges for operations of our assets and costs allocated by QEP. These costs are reimbursed and relate to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) restructuring, compensation, share-based

F-29

compensation, and pension and post-retirement costs. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and its proportionate share of QEP’s gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies are reasonable.

The following table summarizes the related party income statement transactions with QEP:


	Years Ended December 31,
	2012			2011
	(in millions)
Revenues from affiliate	$	79.7		$	69.5
Interest expense to affiliate		(8.7	)		(12.8	)

Note

5 — Property, Plant and Equipment

A summary of the historical cost of the Predecessor’s property, plant and equipment is as follows:


	Estimated useful lives		At December 31,
	Estimated useful lives		2012			2011
			(in millions)
Gathering equipment		5 to 40 years	$	907.7		$	866.8
General support equipment		3 to 30 years		11.1			9.0

Total property, plant and equipment				918.8			875.8
Accumulated depreciation				(284.7	)		(246.7	)

Total net property, plant and equipment			$	634.1		$	629.1

Note

6 — Asset Retirement Obligations

The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:


	Asset Retirement Obligations
	2012		2011
	(in millions)
ARO liability at January 1,	$	13.6	$	12.7
Accretion		1.5		1.4
Liabilities incurred (revision)		1.2		(0.5	)

ARO liability at December 31,	$	16.3	$	13.6

Note

7 — Commitments and Contingencies

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anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Predecessor may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Predecessor’s litigation loss contingencies are discussed below. The Predecessor is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. The Predecessor believes, however, that the resolution of pending proceedings will not have a material effect on the Predecessor’s financial position, results of operations or cash flows.

Environmental Claims

United States of America v. QEP Field Services, Civil No. 208CV167, U.S. District Court for Utah filed on February 28, 2008. The U.S. Environmental Protection Agency (EPA) alleged that QEP Field Services (f/k/a Questar Gas Management) violated the Clean Air Act (CAA) and sought substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. On May 16, 2012, QEP Field Services settled this matter and the parties executed a consent decree which was subsequently approved by court order. The civil penalty paid to the government during the third quarter of 2012 was $3.7 million. A contribution of $0.4 million was paid to a trust created by the Ute Indian Tribe of the Uintah and Ouray Reservation for the implementation of environmental programs for the benefit of Tribal members. The settlement also requires the Company to reduce its emissions by removing certain equipment, installing additional pollution controls and replacing the natural gas powered instrument control systems with compressed air control systems, all of which will require capital expenditures of approximately $2.4 million, of which $1.2 million had been spent as of December 31, 2012. QEP Field Services will have continuing operational compliance obligations under the consent decree at the affected facilities, however only a portion of the required expenditures and compliance items are associated with assets of the Predecessor.

Litigation

Our gathering systems are the subject of ongoing litigation between Questar Gas Company (QGC) and QEP Field Services Company, Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. 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 rate payers. 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 Field Services. As of December 31, 2012, our Predecessor 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 the Partnership as a defendant in the litigation. Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

F-31

Commitments

QEP has contractual cash obligations for operating leases of which a portion is allocated to the Predecessor. These leases have original terms ranging from 10 to 12 years and are classified as operating leases. Allocated rent expense related to these leases was $0.5 million and $0.2 million for 2012 and 2011, respectively. Allocated annual payments and the corresponding years for operating lease contracts are as follows (in millions):


Year	Amount
2013	$	0.6
2014	$	0.6
2015	$	0.7
2016	$	0.7
2017	$	0.7
After 2017	$	3.9

F-32

QEP Midstream Partners, LP

Report of Independent Registered Public Accounting Firm

To the Board of Directors of QEP Midstream Partners GP, LLC, as general partner of QEP Midstream Partners, LP:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of QEP Midstream Partners, LP. (the Partnership) at April 19, 2013 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

May 9, 2013

F-33

QEP Midstream Partners, LP

BALANCE SHEET

April 19, 2013


Assets
Cash	$	—

Total assets	$	—

Partner’s capital
Limited Partner	$	980
General Partner		20
Receivable from Partners		(1,000	)

Total partner’s capital	$	—

See note accompanying this balance sheet.

F-34

NOTE TO BALANCE SHEET

Note 1 — Description of the Business

QEP Midstream Partners, LP (the “Partnership”) is a Delaware limited partnership formed on April 19, 2013. QEP Midstream Partners GP, LLC (the “General Partner”) is a limited liability company formed on April 19, 2013 to become the general partner of the Partnership. QEP Field Services Company (the “Limited Partner”) is a Utah corporation formed on May 18, 1993. The General Partner and the Limited Partner are indirect, wholly owned subsidiaries of QEP Resources, Inc.

On April 19, 2013, the Limited Partner committed to contribute $980 to the Partnership in exchange for a 98% limited partner interest and the General Partner committed to contribute $20 to the Partnership in exchange for a 2% general partner interest. These contributions receivable are reflected as a reduction of equity in accordance with generally accepted accounting principles. There have been no other transactions involving the Partnership as of April 19, 2013.

The Partnership intends to offer common units, representing limited partner interests, pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership to the Limited Partner, and general partner units representing an aggregate 2% general partner interest in the Partnership to the General Partner.

F-35

APPENDIX A

FORM OF FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP OF QEP MIDSTREAM PARTNERS, LP

[To be filed by Amendment]

A-1

APPENDIX B

GLOSSARY OF TERMS

barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

BBls/d: Barrels per day.

Btu: One British thermal unit — a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

Cf: Cubic foot or feet is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard temperature (60 degrees Fahrenheit) and standard pressure (14.73 pounds standard per square inch).

common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined products or other hydrocarbon-based products as a common carrier for hire.

crude oil: A mixture of hydrocarbons that exists in liquid phase in underground reservoirs.

EIA: United States Energy Information Administration.

end user: The ultimate user and consumer of transported energy products.

FERC: Federal Energy Regulatory Commission.

life-of-reserves contract: A contract that remains in effect as long as commercial production of hydrocarbons is ongoing.

MBbls: One thousand barrels.

MBbls/d: One thousand barrels per day.

MMBtu: One million Btu.

MMcf: One million Cf.

NGL: Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

throughput: The volume of crude oil or hydrocarbon-based products transported or passing through a pipeline, plant, terminal or other facility during a particular period.

B-1

Common Units

Representing Limited Partner Interests

PROSPECTUS

, 2013

Wells Fargo Securities

Part II

Information not required in the registration statement

Item 13.

Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NYSE filing fee, the amounts set forth below are estimates.


SEC registration fee	$	54,560
FINRA filing fee		60,500
NYSE listing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*

Total	$	*

*	To be filed by amendment.

Item 14.

Indemnification of Directors and Officers

The section of the prospectus entitled “Our Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the Underwriting Agreement to be filed as an exhibit to this registration statement in which QEP Midstream Partners, LP and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15.

Recent Sales of Unregistered Securities

On April 19, 2013, in connection with the formation of the partnership, QEP Midstream Partners, LP issued to (i) QEP Midstream Partners GP, LLC, the 2.0% general partner interest in the partnership for $20 and (ii) to QEP Field Services Company, a wholly owned subsidiary of QEP Resources, Inc., the 98.0% limited partner interest in the partnership for $980. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering. There have been no other sales of unregistered securities within the past three years.

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Item 16.

Exhibits

The following documents are filed as exhibits to this registration statement:


Exhibit Number		Description

1.1*		Form of Underwriting Agreement (including form of Lock-up Agreement)

3.1**		Certificate of Limited Partnership of QEP Midstream Partners, LP

3.2*		Form of First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (included as Appendix A to the Prospectus)

5.1*		Opinion of Latham & Watkins LLP as to the legality of the securities being registered

8.1*		Opinion of Latham & Watkins LLP relating to tax matters

10.1*		Form of Credit Agreement

10.2*		Form of Contribution, Conveyance and Assumption Agreement

10.3		Form of Long-Term Incentive Plan

10.4		Form of Phantom Unit Award Agreement

10.5*		Form of Omnibus Agreement

10.6†		Gas Gathering Agreement, dated September 1, 1993, between Questar Gas Company (f/k/a Mountain Fuel Supply Company) and QEP Field Services Company (f/k/a Questar Pipeline Company)

10.7†		Amendment to the Gas Gathering Agreement, dated February 6, 1998, between Questar Gas Company and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.8†		Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.9†		First Amendment, dated March 1, 2006, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.10		Second Amendment, dated August 16, 2007, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.11†		Third Amendment, dated March 2, 2010, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.12†		Fourth Amendment, dated July 1, 2011, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

21.1		List of Subsidiaries of QEP Midstream Partners, LP

23.1		Consent of PricewaterhouseCoopers LLP

23.2*		Consent of Latham & Watkins LLP (contained in Exhibit 5.1)

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Exhibit Number		Description

23.3*		Consent of Latham & Watkins LLP (contained in Exhibit 8.1)

24.1		Powers of Attorney (contained on the signature page to this Registration Statement)

*	To be filed by amendment.

**	Previously submitted

†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

Item 17.

Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. If a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424 (§ 230.424 of this chapter);

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

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The undersigned registrant hereby undertakes that,

(i) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(ii) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with QEP or its subsidiaries (including the registrant’s general partner) and of fees, commissions, compensation and other benefits paid, or accrued to QEP or its subsidiaries (including the registrant’s general partner) for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

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Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on July 3, 2013.


QEP Midstream Partners, LP

BY:		QEP Midstream Partners GP, LLC,
		its General Partner

BY:		/s/ Charles B. Stanley
		Charles B. Stanley Chairman of the Board of Directors and Chief Executive Officer

The person whose signature appears below appoints Charles B. Stanley and Richard J. Doleshek, and each of them, any of whom may act without the joinder of the other, as her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for her and in her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.


Signature	Title	Date
/s/ Charles B. Stanley Charles B. Stanley	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	July 3, 2013

* Richard J. Doleshek	Director, Executive Vice President and Chief Financial Officer (Principal Financial Officer)	July 3, 2013

* Kendall K. Carbone	Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	July 3, 2013

* Perry H. Richards	Director, Senior Vice President and General Manager	July 3, 2013

* S. Scott Gutberlet	Director	July 3, 2013


	Signature	Title	Date

	/s/ Susan O. Rheney Susan O. Rheney	Director	July 3, 2013

*By:	/s/ Charles B. Stanley Charles B. Stanley
	Attorney-in-fact

Exhibit Index


Exhibit Number		Description

1.1*		Form of Underwriting Agreement (including form of Lock-up Agreement)

3.1**		Certificate of Limited Partnership of QEP Midstream Partners, LP

3.2*		Form of First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (included as Appendix A to the Prospectus)

5.1*		Opinion of Latham & Watkins LLP as to the legality of the securities being registered

8.1*		Opinion of Latham & Watkins LLP relating to tax matters

10.1*		Form of Credit Agreement

10.2*		Form of Contribution, Conveyance and Assumption Agreement

10.3		Form of Long-Term Incentive Plan

10.4		Form of Phantom Unit Award Agreement

10.5*		Form of Omnibus Agreement

10.6†		Gas Gathering Agreement, dated September 1, 1993, between Questar Gas Company (f/k/a Mountain Fuel Supply Company) and QEP Field Services Company (f/k/a Questar Pipeline Company)

10.7†		Amendment to the Gas Gathering Agreement, dated February 6, 1998, between Questar Gas Company and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.8†		Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.9†		First Amendment, dated March 1, 2006, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.10		Second Amendment, dated August 16, 2007, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.11†		Third Amendment, dated March 2, 2010, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

10.12†		Fourth Amendment, dated July 1, 2011, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company)

21.1		List of Subsidiaries of QEP Midstream Partners, LP

23.1		Consent of PricewaterhouseCoopers LLP

23.2*		Consent of Latham & Watkins LLP (contained in Exhibit 5.1)

23.3*		Consent of Latham & Watkins LLP (contained in Exhibit 8.1)

24.1		Powers of Attorney (contained on the signature page to this Registration Statement)

*	To be filed by amendment.

**	Previously submitted

†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

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