EX-99.1

I am pleased to inform you that on , 2014, the board of directors of QEP Resources, Inc. (“QEP”) approved the spin-off of our midstream field services business as a separate, publicly traded company, which we have named Entrada Midstream, Inc. (formerly QEP Field Services Company), or Entrada. Upon completion of the spin-off, QEP stockholders will own 100% of the outstanding shares of common stock of Entrada. We believe that this separation of Entrada to form a new, independent, publicly traded company is in the best interests of QEP, its stockholders and Entrada.

The spin-off will be completed by way of a pro rata distribution on , 2014, of Entrada common stock to our stockholders of record as of the close of business on , 2014, the spin-off record date. Each QEP stockholder will receive shares of Entrada common stock for every shares of QEP common stock held by such stockholder on the record date. The distribution of these shares will be made in book-entry form, which means that no physical share certificates will be issued. Following the spin-off, stockholders may request that their shares of Entrada common stock be transferred to a brokerage or other account at any time. No fractional shares of Entrada common stock will be issued. If you would otherwise have been entitled to a fractional common share in the distribution, you will receive the net cash proceeds of the sale of such fractional share instead.

The spin-off is subject to certain customary conditions. Stockholder approval of the distribution is not required, nor are you required to take any action to receive your shares of Entrada common stock.

Immediately following the spin-off, you will own common stock in QEP and Entrada. QEP’s common stock will continue to trade on the New York Stock Exchange under the symbol “QEP.” We intend to file an application to list Entrada’s common stock on the New York Stock Exchange under the symbol “EMID.”

It is a condition to the completion of the distribution that QEP receive an opinion from its tax counsel, Latham & Watkins LLP, substantially to the effect that the spin-off will qualify as a tax-free distribution to QEP and QEP stockholders, except with respect to any cash received in lieu of fractional shares.

The enclosed information statement, which is being mailed to all QEP stockholders, describes the spin-off in detail and contains important information about Entrada, including its consolidated financial statements. We urge you to read this information statement carefully.

I want to thank you for your continued support of QEP. We look forward to your support of Entrada in the future.

It is our pleasure to welcome you as a stockholder of our company, Entrada Midstream, Inc., or Entrada. We are a midstream field services business engaged in providing natural gas gathering, processing, treating and transportation services and natural gas liquids, or NGL, fractionation and transportation services for our producer customers.

As an independent, publicly traded company, we believe we can more effectively focus on our objectives and satisfy the capital needs of our company, and thus bring more value to you as a stockholder than we could as an operating segment of QEP Resources, Inc. (“QEP”).

We intend to file an application to list our common stock on the New York Stock Exchange under the symbol “EMID” in connection with the distribution of our common stock by QEP.

We invite you to learn more about Entrada and our subsidiaries by reviewing the enclosed information statement. We look forward to our future as an independent, publicly traded company and to your support as a holder of Entrada common stock.

Information contained herein is subject to completion or amendment. A Registration Statement on Form 10 relating to these securities has been filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended.

This information statement is being sent to you in connection with the separation of Entrada Midstream, Inc. (formerly QEP Field Services Company), or Entrada, from QEP Resources, Inc., or QEP, following which Entrada will be an independent, publicly traded company. As part of the separation, QEP will distribute all of the shares of Entrada common stock on a pro rata basis to the holders of QEP’s common stock. We refer to this pro rata distribution as the “distribution” and we refer to the separation, including the restructuring transactions (which will precede the separation) and the distribution, as the “spin-off.” It is a condition to the completion of the distribution that QEP receive an opinion from its tax counsel, Latham & Watkins LLP, substantially to the effect that the spin-off will be tax-free to QEP and QEP stockholders for U.S. federal income tax purposes under Section 355 of the Internal Revenue Code of 1986 (the “Code”), except to the extent of cash received in lieu of fractional shares. Each QEP stockholder will receive shares of Entrada common stock for every shares of QEP common stock held by such stockholder as of the close of business on , 2014, the record date for the distribution. The distribution of shares will be made in book-entry form. QEP will not distribute any fractional shares of Entrada common stock. Instead, the distribution agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds from the sales pro rata to each holder who would otherwise have been entitled to receive a fractional share in the spin-off. See “The Spin-Off—Treatment of Fractional Shares.” As discussed under “The Spin-Off—Trading Prior to the Distribution Date,” if you sell your common shares of QEP in the “regular-way” market after the record date and before the distribution date, you also will be selling your right to receive shares of our common stock in connection with the separation. The distribution will be effective as of 11:59 p.m., Eastern time, on , 2014. Immediately after the distribution becomes effective, we will be an independent, publicly traded company.

No vote or action of QEP stockholders is required in connection with the spin-off. We are not asking you for a proxy. QEP stockholders will not be required to pay any consideration for the shares of Entrada common stock they receive in the spin-off, and they will not be required to surrender or exchange shares of their QEP common stock or take any other action in connection with the spin-off.

All of the outstanding shares of Entrada common stock are currently owned by QEP. Accordingly, there is no current trading market for Entrada common stock. We expect, however, that a limited trading market for Entrada common stock, commonly known as a “when-issued” trading market, will develop on or shortly before the record date for the distribution, and we expect “regular-way” trading of Entrada common stock will begin the first trading day after the distribution date. We intend to file an application to list Entrada common stock on the New York Stock Exchange under the ticker symbol “EMID.”

We are an “emerging growth company” as defined under the federal securities laws. For implications of our status as an “emerging growth company,” please see “Summary —Our Emerging Growth Company Status” beginning on page 9. In reviewing this information statement, you should carefully consider the matters described in “Risk Factors” beginning on page 23 of this information statement.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement is not an offer to sell, or a solicitation of an offer to buy, any securities.

This information statement was first mailed to QEP stockholders on or about , 2014.

This information statement is being furnished solely to provide information to QEP stockholders who will receive shares of Entrada common stock in connection with the spin-off. It is not provided as an inducement or encouragement to buy or sell any securities. You should not assume that the information contained in this information statement is accurate as of any date other than the date set forth on the cover. Changes to the information contained in this information statement may occur after that date, and we undertake no obligation to update the information contained in this information statement, unless we are required by applicable securities laws to do so.

SUMMARY

The following is a summary of some of the information contained in this information statement. It does not contain all the details concerning us or the spin-off, including information that may be important to you. We urge you to read this entire document carefully, including the risk factors, our historical and pro forma financial statements and the notes to those financial statements included elsewhere in this information statement.

Except where the context otherwise requires or where otherwise indicated, (1) all references to “QEP” refer to QEP Resources, Inc. and its subsidiaries, other than us and our subsidiaries, (2) all references to the “Company,” “we,” “us” and “our” when used in a historical context refer to QEP Field Services Company (“QEPFS”), a Delaware corporation, and its subsidiaries and when used in the present or future tense refer to Entrada Midstream, Inc. (“Entrada” or “EMID”) and its subsidiaries on a consolidated basis, including QEPM, after giving effect to the spin-off and (3) all references to “QEPM,” “QEP Midstream Partners” and the “Partnership” refer to QEP Midstream Partners, LP. Immediately prior to completion of the spin-off, we will file an amendment with the Secretary of State of the State of Delaware to change our name to Entrada. Green River Processing, LLC, or Green River Processing, a Delaware limited liability company, is currently our wholly owned subsidiary. On May 7, 2014, we entered into a Purchase and Sale Agreement (the “Purchase and Sale Agreement”) with QEPM wherein we agreed to sell a 40% interest in Green River Processing to the Partnership. The transaction is expected to close on July 1, 2014, subject to customary closing conditions. For purposes of this information statement, unless the context otherwise requires, we have assumed that the transactions contemplated by the Purchase and Sale Agreement will close on July 1, 2014. Although we will only own (i) a 60% interest in Green River Processing, (ii) a 71.5% interest in the Vermillion processing complex, and (iii) a 38% interest in Uintah Basin Field Services, LLC, or Uintah Basin Field Services, we refer to these assets or the assets owned by each of these entities as our assets.

Our historical financial results contained in this information statement may not be indicative of our financial results in the future as an independent company or reflect what our financial results would have been had we been an independent company during the periods presented. Unless specifically stated otherwise, historical financial and operating data is shown on a pro forma basis to reflect the transfer of our Haynesville gathering system (the “Haynesville Gathering System”) to QEP prior to the completion of the spin-off. We have provided definitions for some of the terms we use to describe our business and industry in this information statement in the “Glossary of Terms” beginning on page B-1 of this information statement.

Entrada Midstream, Inc.

We are currently a wholly owned subsidiary of QEP Resources, Inc., which is a holding company with three major lines of business: crude oil and natural gas exploration and production; midstream field services; and energy marketing. QEP had consolidated revenue for the year ended December 31, 2013, and three months ended March 31, 2014, in excess of $2.9 billion and $884.0 million, respectively, and trades on the New York Stock Exchange, or NYSE, under the symbol “QEP.” Following the spin-off, we will be an independent, publicly traded company. QEP will not retain any ownership interest in us.

markets, including various interstate and intrastate pipelines. Finally, we own (i) an approximate 55.8% limited partner interest in QEP Midstream Partners, LP, a publicly traded crude oil and natural gas gathering partnership (NYSE: QEPM), consisting of 3,701,750 common units and 26,705,000 subordinated units and (ii) 100% of QEPM’s general partner, which owns the 2.0% general partner interest in QEPM and 100% of QEPM’s incentive distribution rights. In addition to the 40% interest in Green River Processing, QEPM’s assets consist of ownership interests in four gathering systems and two Federal Energy Regulatory Commission (“FERC”) regulated pipelines through which it provides natural gas and crude oil gathering and transportation services.

As of and for the three months ended March 31, 2014, our gathering systems had 2,222 miles of pipeline and an average gross throughput of 1.8 million MMBtu/d of natural gas and approximately 15,267 Bbl/d of crude oil. For the three months ended March 31, 2014, our (i) average processing throughput was 800 thousand MMBtu/d and (ii) average fractionation throughput was 11,917 Bbl/d.

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, 2014, approximately 84% of our revenue was generated pursuant to contracts with remaining terms in excess of five years, including 59% of our gathering revenue that was generated pursuant to “life-of-reserves” contracts. We provide our processing, treating and fractionation services through fee-based and keep-whole arrangements. For the three months ended March 31, 2014, approximately 43% of our processing, treating and fractionation revenue was generated pursuant to fee-based arrangements. In addition to our fee-based and keep-whole arrangements, for the three months ended March 31, 2014, approximately 3% of our revenue was generated through the sale of condensate volumes that we collect on our gathering systems.

We have secured significant acreage dedications from several of our largest customers, including QEP. We believe that current drilling activity on acreage dedicated to us should maintain or increase our existing throughput levels on our gathering systems and processing and fractionation facilities 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 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. In addition, several of our gathering and processing contracts are underpinned by minimum volume commitments that are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective agreement, whether by collecting gathering fees on throughput volumes, processing fees on actual volumes processed or from cash payments to cover any minimum volume commitment shortfall. At March 31, 2014, we had an aggregate of approximately 162 Bcf of processing minimum volume commitments with original terms that range from 10 years to 18 years and, as of March 31, 2014, had a weighted average remaining life of approximately 8 years, assuming minimum volumes for the remainder of the term. At March 31, 2014, we had an aggregate of approximately 161 Bcf of minimum volume commitments and 30 Bcf of capacity reservations on our gathering systems with original terms that range from 5 years to 20 years and, as of March 31, 2014, had a weighted average remaining life of approximately 6 years assuming minimum volumes for the remainder of the term.

Our Assets and Operations

The following table provides information regarding our assets as of March 31, 2014:

Gathering


Gathering System	Primary Location		Length *(miles)*		Receipt Points		Compression *(bhp)*		Throughput Capacity **(MMcf/d)⁽¹⁾**		Average Daily Throughput (Thousand MMBtu/d)⁽¹⁾
Uinta Basin Gathering System		Uinta Basin		610		1,957		54,306		299		177
Uintah Basin Field Services⁽²⁾		Uinta Basin		100		21		5,360		26		10

Total				710		1,978		59,666		325		187

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2014.

(2)	Our ownership interest in Uintah Basin Field Services is 38%.

Uinta Basin Gathering System

The Uinta Basin gathering system (“Uinta Basin Gathering System”) consists of natural gas gathering systems and compression assets located in northeast Utah, which include a combined 610 miles of low-pressure gathering pipeline and 54,306 brake horsepower, or bhp, of natural gas compression. We refer to these individual gas gathering systems collectively as the Uinta Basin Gathering System. The gathering system is primarily supported by acreage dedications and long-term, fee-based gathering agreements that contain annual inflation adjustment mechanisms and minimum volume commitments. For the three months ended March 31, 2014, approximately 95% of the throughput volumes on the gathering system were gathered pursuant to contracts with remaining terms of more than four years. The primary customers on these assets include EOG Resources, Inc. (“EOG”) and QEP. The gathering system has a combined total throughput capacity of 299 MMcf/d and had average gross throughput of approximately 177 thousand MMBtu/d for the three months ended March 31, 2014.

Uintah Basin Field Services

Uintah Basin Field Services is a joint venture between us, Discovery Natural Resources LLC (formerly FIML Natural Resources, LLC) (“Discovery”), and Ute Energy Midstream Holdings, LLC (“Ute Energy”) that was formed to allow the partners to jointly develop the natural gas gathering infrastructure within a defined area of mutual interest located in the southeastern Uinta Basin. The gathering system consists of approximately 100 miles of gathering pipeline and 5,360 bhp of gas compression and is operated by us. The gathering system is supported by long-term, fee-based gas gathering agreements that contain firm throughput commitments, which generate fees whether or not the capacity is used. The system is currently fully subscribed due to these firm commitments, but we believe we can easily expand this system by adding incremental compression or looping a portion of the existing pipeline. The primary customers on these assets include QEP, Discovery and Ute Energy. The gathering system has total throughput capacity of approximately 26 MMcf/d and had average gross throughput of 10 thousand MMBtu/d for the three months ended March 31, 2014.

Processing/Treating/Fractionation

Asset

Primary
Location

Asset Type

Facility Type

Throughput
Capacity
(MMcf/d)⁽¹⁾

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

Blacks Fork Complex⁽²⁾

Green River
Basin

Processing

Cryogenic /
Joule-Thomson

835

430

Fractionation

Fractionator

15,000

⁽³⁾

11,917

⁽³⁾

Emigrant Trail Complex⁽²⁾

Green River
Basin

Processing

Cryogenic

Vermillion Complex⁽⁴⁾

Southern Green
River Basin

Processing

Cryogenic

⁽⁵⁾

Uinta Basin Complex

Uinta Basin

Processing

Cryogenic /
Refrigeration

650

276

Total

Processing

1,583

Fractionation

15,000

⁽³⁾

(1)	Represents 100% of the capacity and throughput of the assets as of and for the three months ended March 31, 2014.

(2)

We currently own 100% of Green River Processing, which owns the Blacks Fork and Emigrant Trail processing complexes. At the closing of the transactions contemplated by the Purchase and Sale Agreement, which is expected to occur on July 1, 2014, we will own a 60% interest in Green River Processing, and QEPM will own the remaining 40% interest.

(3)	Throughput measured in barrels of NGL per day.

(4)	Our ownership interest in the Vermillion processing complex is 71.5%.

(5)	An expansion project is currently in progress that will increase total inlet capacity to approximately 57 MMcf/d in the third quarter of 2014.

Blacks Fork Complex

The Blacks Fork processing complex (“Blacks Fork Complex”), located in Sweetwater and Uinta counties, Wyoming, consists of three separate gas processing trains with total raw gas inlet processing capacity of up to 835 MMcf/d, depending on operating mode, and an NGL fractionation facility with total inlet capacity of approximately 15,000 Bbl/d. The complex processed an average of approximately 430 thousand MMBtu/d of natural gas and fractionated an average of 11,917 Bbl/d of NGL during the three months ended March 31, 2014. We are party to a gas conditioning agreement (the “Gas Conditioning Agreement”) with QEPM whereby QEPM has agreed to make available to us at the Blacks Fork Complex natural gas volumes that it has gathered pursuant certain “life-of-reserves” and long-term, natural gas gathering agreements with several producer customers. Pursuant to the terms of the Gas Conditioning Agreement, we have been assigned QEPM’s conditioning and keep-whole processing rights detailed in the underlying gathering agreements. For a description of the Gas Conditioning Agreement, please read “Arrangements Between QEP and Our Company and Other Related Party Transactions—Agreements Between QEP and Us—Gas Conditioning Agreement.”

Approximately 68% of inlet volumes for the three months ended March 31, 2014, were processed under a fee-based agreement with a remaining term of more than 12 years. Approximately 30% of inlet volumes for the three months ended March 31, 2014, at the Blacks Fork Complex were processed under the Gas Conditioning Agreement. The primary customers supplying the Blacks Fork Complex include QEP, Ultra Petroleum Corporation (“Ultra”) and Questar Corporation (“Questar”). The complex receives the majority of its gas from the Pinedale Anticline and the Moxa Arch fields located in the Green River Basin of western Wyoming.

Emigrant Trail Complex

The Emigrant Trail processing complex (“Emigrant Trail Complex”), located in Uinta County, Wyoming, consists of one cryogenic gas processing train with total raw gas inlet capacity of approximately 55 MMcf/d and had average daily throughput of approximately 48 thousand MMBtu/d for the three months ended March 31, 2014. The complex is supported by fee-based and keep-whole processing agreements. The primary customers supplying the Emigrant Trail Complex include Questar and Anadarko Petroleum Corporation (“Anadarko”). The complex receives the majority of its gas from various gas fields along the Moxa Arch, including Church Buttes, located in the Green River Basin of western Wyoming.

Vermillion Complex

The Vermillion processing complex (“Vermillion Complex”), located in Sweetwater County, Wyoming, consists of one cryogenic processing train with total raw gas inlet capacity of approximately 43 MMcf/d and had average daily throughput of 45 thousand MMBtu/d for the three months ended March 31, 2014. Pursuant to the terms of the Gas Conditioning Agreement, QEPM has agreed to make available to us at the Vermillion Complex natural gas volumes that it has gathered pursuant to certain natural gas gathering agreements with several producer customers. Pursuant to the terms of the Gas Conditioning Agreement, we have been assigned QEPM’s conditioning and processing rights detailed in the underlying gathering agreements. For a description of the Gas Conditioning Agreement, please read “Arrangements Between QEP and Our Company and Other Related Party Transactions—Agreements Between QEP and Us—Gas Conditioning Agreement.”

Approximately 74% of the inlet volumes for the three months ended March 31, 2014, were processed under fee-based agreements. Approximately 26% of inlet volumes for the three months ended March 31, 2014, at the Vermillion Complex were processed under the Gas Conditioning Agreement. The primary customers supplying the Vermillion Complex include Questar, Devon Energy Corporation (“Devon”), QEP and Chevron Corporation (“Chevron”). The plant receives the majority of its gas from the Canyon Creek, Trail and Hiawatha fields in the Vermillion sub-basin in southern Wyoming and northwest Colorado. An expansion project is currently in progress that will increase total inlet capacity to approximately 57 MMcf/d in the third quarter of 2014.

Uinta Basin Complex

The Uinta Basin processing complex (“Uinta Basin Complex”), located in Uintah County, Utah, consists of four separate processing trains with total raw gas inlet processing capacity of up to 650 MMcf/d. The complex had average daily throughput of approximately 276 thousand MMBtu/d for the three months ended March 31, 2014. The Uinta Basin Complex is supported by long-term, fee-based processing agreements with minimum volume commitments. Approximately 72% of inlet volumes for the three months ended March 31, 2014, at the complex were processed pursuant to contracts with remaining terms of more than six years. The primary customers supplying the Uinta Basin Complex include EOG, QEP, EnerVest, Ltd. (“EnerVest”) and XTO Energy, Inc. (“XTO”). The complex receives the majority of its gas from various natural gas fields located in the Uinta Basin.

QEP Midstream Partners, LP

QEP Midstream Partners, LP is a limited partnership formed to own, operate, acquire and develop midstream energy assets. QEPM’s primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which it provides natural gas and crude oil gathering and transportation services. In addition, upon the closing of the transactions contemplated by the Purchase and Sale Agreement, which is expected to occur on July 1, 2014, QEPM will own a 40% interest in Green River Processing, which owns the Blacks Fork and Emigrant Trail complexes. QEPM’s assets are located in, or are within close proximity to, the Green River Basin, the Uinta Basin, and the Williston Basin located in North Dakota.

The following table provides information regarding QEPM’s assets by system as of March 31, 2014:


Gathering System	Asset Type	Length *(miles)*		Receipt Points		Compression *(bhp)*		Throughput Capacity **(MMcf/d)⁽¹⁾**			Average Daily Throughput (Thousand MMBtu/d)⁽¹⁾
Green River System
Green River Gathering Assets	Gas Gathering		373		317		41,053		737			522
	Oil Gathering		56		103		—		7,137	⁽²⁾		3,377	⁽²⁾
	Water Gathering		88		103		—		21,990	⁽³⁾		11,954	⁽³⁾
	Oil Transmission⁽⁵⁾		61		12		—		40,800	⁽²⁾		8,893	⁽²⁾
Rendezvous Gas Services, L.L.C.⁽⁴⁾	Gas Gathering		310		3		7,800		1,032			618
Rendezvous Pipeline Company, L.L.C.⁽⁵⁾	Gas Transmission		21		1		—		450			210
Vermillion Gathering System	Gas Gathering		517		505		23,932		212			122
Three Rivers Gathering, LLC⁽⁶⁾	Gas Gathering		52		8		4,735		212			115
Williston Gathering System	Gas Gathering		17		35		239		3			2
	Oil Gathering		17		35		—		7,000	⁽²⁾		2,997	⁽²⁾

Total			1,512		1,122		77,759

(1)	Represents 100% of the capacity and throughput of the systems as of and for the three months ended March 31, 2014.

(2)	Capacity and throughput measured in barrels of crude oil per day.

(3)	Capacity and throughput measured in barrels of water per day.

(4)	QEPM’s ownership interest in Rendezvous Gas Services, L.L.C. is 78%.

(5)	FERC-regulated pipeline.

(6)	QEPM’s ownership interest in Three Rivers Gathering, L.L.C. is 50%.

Business Strategies

Our principal business objective is to increase stockholder value over time by pursuing the following business strategies:

•

Pursue economically attractive organic growth opportunities and third-party acquisitions. We intend to continue to evaluate and execute midstream projects that enhance our existing assets. For example, we are currently expanding throughput capacity at our Vermillion Complex from 43 MMcf/d to 57 MMcf/d. The expansion is expected to come online during the third quarter of 2014, and it will be supported by volumes currently bypassing the plant and comingled with drier gas to meet pipeline specifications. In addition, we intend to seek opportunities that will complement, expand and diversify our asset base through acquisitions from third parties if and when they become available.

•

Attract 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 facilities. We believe that the location of our current assets and their direct connection to multiple interstate pipelines provides us with a competitive advantage that will attract additional third-party volumes in the future. In addition, as an independent midstream company, we believe we will be able to attract additional throughput volumes from third-party producers that would otherwise not be willing to dedicate volumes to us as a result of our affiliation with an exploration and production company.

•

Manage contract mix and commodity price exposure to optimize profitability. For the year ended December 31, 2013, approximately 80% of our net operating revenue was generated from fee-based revenue, including demand charges. We expect to continue to enter into fee-based contracts that limit our direct exposure to commodity price risk and provide cash flow stability. The remaining portion is generated from contracts with varying degrees of commodity price exposure, which will benefit us in increasing commodity price environments but reduce our profitability in decreasing commodity price environments. We seek to mitigate our downside to direct commodity exposure by employing a prudent risk management strategy. We believe that our contract mix, combined with our risk management strategy, allows us to optimize our profitability over time by allowing us to take advantage of higher commodity price environments and mitigating our downside exposure in lower commodity price environments.

•

Support QEPM in executing its primary business objective of increasing the quarterly distributions it pays to its unitholders. We own a 55.8% limited partner interest and a 2.0% general partner interest in QEPM and all of QEPM’s incentive distribution rights, which provide us with substantial revenue in the form of quarterly distributions. We expect to increase stockholder value (i) by actively assisting QEPM in executing its primary business objective of increasing the quarterly distributions it pays to its unitholders, (ii) by assisting QEPM in identifying, evaluating and pursuing acquisitions and growth opportunities and (iii) in general, by allowing QEPM the first opportunity to pursue any acquisition or internal growth project that may be presented to us which is within the scope of QEPM’s operations or business strategy. In the long term, we expect that our assets will consist almost exclusively of limited and general partner interests and incentive distribution rights in QEPM. As our existing assets develop and mature, we expect to facilitate the growth of QEPM by offering QEPM the opportunity to purchase all or substantially all of our assets for additional limited partner interests, cash or a combination thereof. For example, we entered into a Purchase and Sale Agreement with QEPM on May 7, 2014, pursuant to which we agreed to sell a 40% ownership interest in Green River Processing for $230.0 million in cash consideration. In addition, we may acquire and/or develop assets that require a significant amount of capital expenditures in order to mitigate potential risks to QEPM related to development and cash flow, which will help ensure cash-flow stability prior to such projects being made available to QEPM. We are under no obligation to sell, and QEPM is under no obligation to buy, additional assets.

Competitive Strengths

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

•

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. We believe that the producing assets connected to our systems are some of the most prolific and lowest cost natural gas and crude oil fields in our operating areas. Our assets have access to major natural gas and crude oil markets via direct connections to interstate and intrastate pipelines. Our direct connections allow producers to select from various markets to sell their natural gas and crude oil production 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 natural gas and crude oil production to a specific interstate pipeline.

•

Integrated midstream value chain. We provide a comprehensive package of services to natural gas and crude oil producers, including natural gas and crude oil gathering, compression, transportation and, with respect to natural gas, processing and NGL fractionation and transportation. We believe our ability to move producers’ natural gas, crude oil and NGL from the wellhead to the market provides a competitive advantage relative to competing companies that do not offer this range of midstream services.

•

Experienced operating team. Our operating team has extensive experience in building, operating and managing large-scale midstream and other energy assets. In addition, we employ engineering, construction and operations teams that have significant experience in designing, constructing and operating large-scale, complex midstream energy assets.

•

Financial flexibility and strong capital structure. Following the spin-off, we expect to have $ of debt and borrowing capacity of approximately $ million, calculated in accordance with the provisions of our new $ million credit facility (the “Credit Facility”). In addition, at the spin-off, we expect QEPM to have $ of debt and borrowing capacity of approximately $ million, calculated in accordance with the provisions of QEPM’s $500 million 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.

•

Strong commercial relationship with QEP. We believe that one of our principal strengths will be our commercial relationship with QEP. QEP is actively operating in the Rocky Mountain region and as of December 31, 2013, served as the operator for 3.1 Tcfe of gross proved reserves, which are subject to long-term contracts with acreage dedications on our gathering systems or directly or indirectly, as the case may be, to long-term contracts with minimum volume commitments on our gathering systems and processing assets. Approximately 47% and 51% of our natural gas gathering and transportation throughput during the year ended December 31, 2013 and the three months ended March 31, 2014, respectively, was attributable to natural gas production owned or controlled by QEP. Approximately 50% and 45% of our processing throughput during the year ended December 31, 2013 and the three months ended March 31, 2014, respectively, was attributable to natural gas production owned or controlled by QEP.

Other Information

We were initially incorporated under the laws of the State of Utah in May 1993, and re-domiciled in Delaware in June 2013. Our principal executive offices are located at , and our telephone number is . Following the completion of the spin-off, our website will be located at www. .com and will be activated in connection with the closing of the spin-off. 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 information statement and does not constitute a part of this information statement.

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 (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:

•

an exemption to provide less than five years of selected financial data in a registrant’s first registration statement that became effective under the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”);

•

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

•

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

•

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

•

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

•

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

We may take advantage of any of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of the spin-off, (ii) the last day of the fiscal year in which we have more than $1.0 billion in annual revenue, (iii) the date on which we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Exchange Act, which generally requires more than $700 million in market value of our common stock held by non-affiliates as of June 30 of the year such determination is made 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, including 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 information statement may be different from the information you may receive from other public companies in which you hold equity interests.

The Spin-Off

On , 2014, QEP approved the spin-off of Entrada from QEP, following which we will be an independent, publicly owned company. As part of the spin-off, we will transfer to QEP certain assets and liabilities associated with our Haynesville Gathering System, and we will amend and restate our certificate of incorporation and bylaws. These transactions are collectively referred to as our “restructuring transactions” throughout this information statement.

We currently depend on QEP for a number of administrative functions. Prior to the completion of the spin-off, we will enter into agreements with QEP related to the separation of our business operations from QEP. These agreements will be in effect as of the completion of the spin-off and will govern various ongoing relationships between QEP and us, including the extent and manner of our dependence on QEP for administrative services following the completion of the spin-off. Under the terms of these agreements, we will be entitled to the ongoing assistance of QEP only for a limited period of time following the spin-off. For more information regarding these agreements, see “Arrangements Between QEP and Our Company and Other Related Party Transactions” and the historical combined financial statements and the notes thereto included elsewhere in this information statement. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. See “Risk Factors—Risks Related to the Spin-Off—Our agreements with QEP require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.”

The distribution of our common stock as described in this information statement is subject to the satisfaction or waiver of certain conditions. In addition, QEP has the right not to complete the spin-off if, at any time prior to the distribution, the board of directors of QEP determines, in its sole discretion, that the spin-off is not in the best interests of QEP or its stockholders or that market conditions are such that it is not advisable to separate us from QEP. See “The Spin-Off—Conditions to the Spin-Off.”

Risk Factors

We face both general and company specific risks and uncertainties relating to our business and our being an independent, publicly owned company. We also are subject to risks related to the spin-off. You should carefully read “Risk Factors” beginning on page 23 of this information statement. In particular:

Risks Related to Our Business

•

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 on our ability to secure new sources of natural gas and crude oil. Any decrease in the volumes of natural gas and crude oil that we gather, process, treat or transport or in the volumes of NGL that we fractionate could adversely affect our business and operating results.

•

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

•

Natural gas and NGL prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and NGL relative to one another, could adversely affect our business, results of operations and financial condition.

•

We have direct exposure to commodity price risk under keep-whole contracts.

•

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

•

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

•

We depend on a relatively limited number of customers for a significant portion of our revenue. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could have a material adverse effect on our business, results of operations and financial condition.

Risks Related to the Spin-Off

•

We may not realize the potential benefits from our separation from QEP.

•

The combined value of QEP and Entrada shares after the spin-off may not equal or exceed the value of QEP shares prior to the spin-off.

•

Our historical and pro forma combined financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.

•

Following the spin-off, we will continue to depend on QEP for a limited time to provide us with certain services for our business. The services that QEP will provide to us following the separation may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with QEP expire.

•

If, following the completion of the spin-off, there is a determination that the spin-off is taxable for U.S. federal income tax purposes because the facts, assumptions, representations, or undertakings underlying the tax opinion are incorrect or for any other reason, then QEP and its stockholders could incur significant income tax liabilities, and we could incur significant corporate tax liabilities.

Risks Related to Our Common Stock

•

No market currently exists for our common stock. We cannot assure you that an active trading market will develop for our common stock.

•

The market price and trading volume of our common stock may be volatile and you may not be able to sell your shares at or above the initial market price of our common stock following the spin-off.

•

Future sales, or the perception of future sales, of our common stock may depress the price of our common stock.

•

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

Questions and Answers about the Spin-off

The following provides only a summary of the terms of the spin-off. For a more detailed description of the matters described below, see “The Spin-Off.”

Q:	What is the spin-off?

The spin-off is the method by which Entrada will separate from QEP. To complete the spin-off, QEP will distribute to its stockholders all of the shares of Entrada common stock. Following the spin-off, Entrada will be a separate company from QEP, and QEP will not retain any ownership interest in Entrada. The number of shares of QEP common stock you own will not change as a result of the spin-off.

Q:	What will I receive in the spin-off?

As a holder of QEP stock, you will retain your QEP shares and will receive shares of Entrada common stock for every shares of QEP common stock you hold as of the record date. Your proportionate interest in QEP will not change as a result of the spin-off. For a more detailed description, see “The Spin-Off.”

Q:	What is Entrada?

Entrada is currently a wholly owned subsidiary of QEP whose shares will be distributed to QEP stockholders if the spin-off is completed. After the spin-off is completed, Entrada will be a public company and will own and operate the midstream field services business that was formerly a part of QEP. That business is referred to as the “midstream business” throughout this information statement.

Q:	When is the record date for the distribution?

A:	The record date will be the close of business of the NYSE on , 2014.

Q:	When will the distribution occur?

The distribution date of the spin-off is , 2014. Entrada expects that it will take the distribution agent, acting on behalf of QEP, one to two weeks after the distribution date to fully distribute the shares of Entrada common stock to QEP stockholders. The ability to trade Entrada shares will not be affected during that time.

Q:	What if I hold my shares through a broker, bank or other nominee?

A:	QEP stockholders who hold their shares through a broker, bank or other nominee will have their brokerage account credited with EMID common stock. For additional information, those stockholders should contact their broker or bank directly.

Q:	What are the reasons for and benefits of separating Entrada from QEP?

The separation of Entrada from QEP and the distribution of Entrada common stock are intended to provide you with equity investments in two separate companies, each of which will be able to focus on its own business. For a more detailed discussion of the reasons for and benefits of the spin-off, see “The Spin-Off—Reasons for the Spin-Off.”

Q:	Why is the separation of Entrada structured as a spin-off as opposed to a sale?

A:	QEP believes that a tax-free distribution of Entrada common stock is an efficient way to separate Entrada from QEP in a manner that will improve flexibility, benefit both QEP and the midstream business and create long-term value for stockholders of both QEP and Entrada.

Q:	What is being distributed in the spin-off?

Approximately shares of Entrada common stock will be distributed in the spin-off, based on the number of shares of QEP common stock expected to be outstanding as of the record date. The actual number of shares of Entrada common stock to be distributed will be calculated on , 2014, the record date. The shares of Entrada common stock to be distributed by QEP will constitute all of the issued and outstanding shares of Entrada common stock immediately prior to the distribution. For more information on the shares being distributed in the spin-off, see “Description of Capital Stock—Common Stock.”

Q:	How will options and other equity-based compensation awards held by Entrada employees be affected as a result of the spin-off?

A:	We are in the process of determining the treatment of QEP options and other equity-based compensation, and we will provide information regarding such treatment in an amendment to this information statement.

Q:	What do I have to do to participate in the spin-off?

A:	You are not required to take any action, although you are urged to read this entire document carefully. No stockholder approval of the distribution is required or sought. You are not being asked for a proxy. No

action is required on your part to receive your shares of Entrada common stock. You will neither be required to pay anything for the new shares nor to surrender any shares of QEP common stock to participate in the spin-off.

Q:	How will fractional shares be treated in the spin-off?

Fractional shares of Entrada common stock will not be distributed. Fractional shares of Entrada common stock to which QEP stockholders of record would otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be distributed ratably to those stockholders who would otherwise have received fractional shares of Entrada common stock. Proceeds from these sales will generally result in a taxable gain or loss to those stockholders. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to such stockholder’s particular circumstances. The tax consequences of the distribution are described in more detail under “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off.”

Q:	What are the conditions to the spin-off?

The spin-off is subject to a number of conditions. See “The Spin-Off—Conditions to the Spin-Off.” However, even if all of the conditions are satisfied, QEP has the right to terminate the spin-off if at any time QEP’s board of directors determines that the spin-off is not in the best interests of QEP and its stockholders.

Q:	What are the U.S. federal income tax consequences of the spin-off?

It is a condition to the completion of the distribution that QEP receive an opinion from its tax counsel, Latham & Watkins LLP, substantially to the effect that, for U.S. federal income tax purposes, the spin-off will be tax-free to QEP and QEP stockholders under Section 355 of the Code, except for cash payments made to QEP stockholders in lieu of fractional shares of Entrada common stock such stockholders would otherwise receive in the distribution. The tax consequences of the distribution are described in more detail under “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off.”

Q:	How will I determine the tax basis I will have in the Entrada shares I receive in the spin-off?

Generally, your aggregate basis in the stock you hold in QEP and the new Entrada shares received in the spin-off will equal the aggregate basis of QEP common stock held by you immediately before the spin-off. This aggregate basis should be allocated between your QEP common stock and the Entrada common stock you receive in the spin-off in proportion to the relative fair market value of each on the date of the distribution. See “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off” included elsewhere in this information statement for more information.

You should consult your tax advisor about how this allocation will work in your situation (including a situation where you have purchased QEP shares at different times or for different amounts) and regarding any particular consequences of the spin-off to you, including the application of state, local and foreign tax laws.

Q:	What are the U.S. federal income tax consequences of the spin-off to our ability to engage in strategic transactions?

We will be contractually prohibited under our Tax Sharing Agreement from taking or failing to take any action that prevents the spin-off and/or certain related transactions from being tax-free. Such actions may include, but not be limited to, any of the following actions within the two-year period following the effective time of the spin-off: (i) selling or transferring all or substantially all of the assets that constitute our midstream business, (ii) except in limited circumstances, issuing stock or equity interests of us or any affiliate (or any instrument that is convertible or exchangeable into any such stock), (iii) facilitating or otherwise participating in any acquisition (or deemed acquisition) of our stock that would result in any shareholder or certain groups of shareholders owning or being deemed to own 50% or more (by vote or

value) of our outstanding stock, and (iv) redeeming or otherwise repurchasing any of our stock. The foregoing actions may also apply to transactions in which QEPM engages. In addition, such actions also contain exceptions for certain permitted cases, including certain transfers among us and our wholly owned subsidiaries, and in some cases allow for actions that do not exceed permitted limits.

These restrictions may limit our ability to pursue strategic transactions or engage in new businesses or other transactions that may maximize the value of our business. For more information, see “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off” and “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement” included elsewhere in this information statement.

Q:	Will the Entrada common stock be listed on a stock exchange?

Yes. Although there is not currently a public market for Entrada common stock, we intend to file an application to list our common stock on the NYSE under the symbol “EMID.” We anticipate that trading of Entrada common stock will commence on a “when-issued” basis on or shortly before the record date. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. When-issued trades generally settle within four trading days after the distribution date. On the first trading day following the distribution date, any when-issued trading with respect to Entrada common stock will end and “regular-way” trading will begin. “Regular-way” trading refers to trading after a security has been issued and typically involves a transaction that settles on the third full trading day following the date of the transaction. See “Trading Market.”

Q:	Will my shares of QEP common stock continue to trade?

A:	Yes. QEP common stock will continue to be listed and trade on the NYSE under the symbol “QEP.”

Q:	If I sell, on or before the distribution date, shares of QEP common stock that I held on the record date, am I still entitled to receive shares of Entrada common stock distributable with respect to the shares of QEP common stock I sold?

Beginning on or shortly before the record date and continuing through the distribution date for the spin-off, QEP’s common stock will begin to trade in two markets on the NYSE: a “regular-way” market and an “ex-distribution” market. If you are a holder of record of shares of QEP common stock as of the record date for the distribution and choose to sell those shares in the regular-way market after the record date for the distribution and before the distribution date, you also will be selling the right to receive the shares of Entrada common stock in connection with the spin-off. However, if you are a holder of record of shares of QEP common stock as of the record date for the distribution and choose to sell those shares in the ex- distribution market after the record date for the distribution and before the distribution date, you will still receive the shares of Entrada common stock in the spin-off.

Q:	Will the spin-off affect the trading price of my QEP stock?

Yes, the trading price of shares of QEP common stock immediately following the distribution is expected to be lower than immediately prior to the distribution because its trading price will no longer reflect the value of the midstream business. However, we cannot provide you with any assurance as to the price at which the QEP shares will trade following the spin-off.

Q:	What if I want to sell my QEP common stock or my Entrada common stock?

You should consult with your financial advisors, such as your stockbroker, bank or tax advisor. Neither QEP nor Entrada makes any recommendations on the purchase, retention or sale of shares of QEP common stock or the Entrada common stock to be distributed. If you decide to sell any shares after the record date, but

before the spin-off, you should make sure that your stockbroker, bank or other nominee understands whether you want to sell your QEP common stock, the Entrada common stock you will receive in the spin-off, or both. If you sell your QEP common stock before the record date, you will not receive shares of Entrada common stock in the spin-off.

Q:	What indebtedness will Entrada have following the spin-off?

A:	We expect to enter into the Credit Facility prior to the completion of the spin-off. See “Description of Material Indebtedness” for a more detailed description of this transaction. At the time of the spin-off, we expect to have $ of outstanding debt and $ of availability under the Credit Facility.

Q:	What will the relationship be between QEP and Entrada after the spin-off?

Following the spin-off, Entrada will be an independent, publicly traded company, and QEP will have no continuing stock ownership interest in Entrada. In connection with the spin-off, Entrada will have entered into a separation and distribution agreement and several other agreements with QEP for the purpose of allocating between Entrada and QEP various assets, liabilities and obligations. These agreements will also govern Entrada’s relationship with QEP following the spin-off and will provide arrangements for employee matters, tax matters and some other liabilities and obligations attributable to periods before and, in some cases, after the spin-off. These agreements will also include arrangements with respect to transition services.

Q:	What will Entrada’s dividend policy be after the spin-off?

We anticipate paying quarterly dividends on our common stock. The payment of cash dividends, if any, will be at the discretion of our Board and will depend upon, among other things, our financial condition, results of operations, earnings and capital requirements of our operating subsidiaries, future business prospects and any restrictions imposed by future debt instruments. For more information, see “Dividend Policy.”

Q:	What are the anti-takeover effects of the spin-off?

Some provisions of the restated certificate of incorporation of Entrada, the restated bylaws of Entrada and Delaware law may have the effect of making more difficult an acquisition of control of Entrada in a transaction not approved by the Board. For example, Entrada’s restated certificate of incorporation and bylaws will provide for a classified board, require advance notice for shareholder proposals and nominations, place limitations on convening shareholder meetings and authorize the Board to issue one or more series of preferred stock. See “Description of Capital Stock—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions” for more information.

Q:	What are the risks associated with the spin-off?

A:	There are a number of risks associated with the spin-off and ownership of Entrada common stock. These risks are discussed under “Risk Factors” beginning on page 23.

Q:	Will I have appraisal rights in connection with the spin-off?

A:	No. Holders of QEP common stock are not entitled to appraisal rights in connection with the spin-off.

Q:	Where can I get more information?

A:	If you have any questions relating to the mechanics of the distribution, you should contact the distribution agent at:

Wells Fargo Shareowner Services

1110 Centre Pointe Curve, Suite 101

Mendota Heights, MN 55120-4100

Attn: Dawn R. Coleman

(651) 450-4053

Before the spin-off, if you have any questions relating to the spin-off, you should contact QEP at:

QEP Resources, Inc.

1050 17^th Street, Suite 800

Denver, CO 80265

Attn: Greg Bensen

(303) 672-6900

After the spin-off, if you have any questions relating to Entrada, you should contact Entrada at:

Entrada Midstream, Inc.

Summary of the Spin-Off

Distributing Company

QEP Resources, Inc., a Delaware corporation. After the distribution, QEP will not own any shares of Entrada common stock.

Distributed Company

Entrada Midstream, Inc., a Delaware corporation and a wholly owned subsidiary of QEP. After the spin-off, Entrada will be an independent, publicly owned company.

Distributed Securities

All of the shares of Entrada common stock owned by QEP, which will be 100% of Entrada’s common stock issued and outstanding immediately prior to the distribution.

Record Date

The record date for the distribution is the close of business on , 2014.

Distribution Date

The distribution date is , 2014.

Restructuring Transactions

As part of the spin-off, we will transfer to QEP the assets and liabilities associated with our Haynesville Gathering System, and we will amend and restate our certificate of incorporation and bylaws.

Indebtedness

Prior to the spin-off, we will enter into the Credit Facility. See “Description of Material Indebtedness” for a more detailed description of this transaction. At the time of the spin-off, we expect to have $ million of borrowings outstanding under our Credit Facility.

Distribution Ratio

Each QEP stockholder will receive shares of Entrada common stock for every shares of QEP common stock held by such stockholder on , 2014.

The Distribution

On the distribution date, QEP will release the shares of Entrada common stock to the distribution agent to distribute to QEP stockholders. The distribution of shares will be made in book-entry form, which means that no physical share certificates will be issued. It is expected that it will take the distribution agent one to two weeks to electronically issue shares of Entrada common stock to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. Trading of our shares will not be affected during that time. Following the spin-off, stockholders whose shares are held in book-entry form may request that their shares of Entrada common stock be transferred to a brokerage or other account at any time. You will not be required to make any payment, surrender or exchange your shares of QEP common stock or take any other action to receive your shares of Entrada common stock.

Fractional Shares

The distribution agent will not distribute any fractional shares of Entrada common stock to QEP stockholders. Fractional shares of Entrada common stock to which QEP stockholders of record would

otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be distributed ratably to those stockholders who would otherwise have received fractional shares of Entrada common stock. Proceeds from these sales will generally result in a taxable gain or loss to those stockholders. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to such stockholder’s particular circumstances. The tax consequences of the distribution are described in more detail under “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off.”

Conditions to the Spin-Off

We expect that the spin-off will be effective on , 2014, provided that the conditions set forth under the caption “The Spin-Off—Conditions to the Spin-Off” have been satisfied in QEP’s sole and absolute discretion.

Trading Market and Symbol

We intend to file an application to list Entrada common stock on the NYSE under the ticker symbol “EMID.” We anticipate that, on or shortly before the record date, trading of shares of Entrada common stock will begin on a “when-issued” basis and will continue up to and including the distribution date, and we expect “regular-way” trading of Entrada common stock will begin the first trading day after the distribution date. We also anticipate that, on or shortly before the record date, there will be two markets in QEP common stock: a regular-way market on which shares of QEP common stock will trade with an entitlement to shares of Entrada common stock to be distributed pursuant to the distribution, and an “ex-distribution” market on which shares of QEP common stock will trade without an entitlement to shares of Entrada common stock. For more information, see “Trading Market.”

Tax Consequences

The spin-off is conditioned on the receipt by QEP of an opinion of its tax counsel, Latham & Watkins LLP, substantially to the effect that the spin-off will be tax-free to QEP and QEP stockholders under Section 355 of the Code. Assuming the validity of the opinion, QEP and QEP stockholders will not recognize any taxable income, gain or loss for U.S. federal income tax purposes as a result of the spin-off, except with respect to any cash received by QEP stockholders in lieu of fractional shares. For a more detailed description of the U.S. federal income tax consequences of the spin-off, see “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off.”

Each stockholder is urged to consult his, her or its tax advisor as to the specific tax consequences of the spin-off to such stockholder, including the effect of any state, local or non-U.S. tax laws and of changes in applicable tax laws.

Relationship with QEP after the Spin-Off

We will enter into a separation and distribution agreement and other ancillary agreements with QEP related to the spin-off. These

agreements will govern the relationship between us and QEP after completion of the spin-off and provide for the allocation between us and QEP of various assets, liabilities and obligations. We intend to enter into a transition services agreement with QEP (the “Transition Services Agreement”) pursuant to which certain services will be provided on an interim basis following the distribution. We also intend to enter into an employee matters agreement that will set forth the agreements between QEP and us concerning certain employee compensation and benefit matters. Further, we intend to enter into a tax sharing agreement with QEP regarding the respective rights, responsibilities and obligations of QEP and us with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. We describe these arrangements in greater detail under “Arrangements Between QEP and Our Company and Other Related Party Transactions,” and describe some of the risks of these arrangements under “Risk Factors—Risks Related to the Spin-Off.”

Indemnities

Under the tax sharing agreement that we intend to enter into with QEP, we may have indemnification obligations to QEP for taxes incurred as a result of the failure of the spin-off to qualify as tax-free under Section 355 of the Code, to the extent caused by our breach of any representations or covenants made in the tax sharing agreement, the separation and distribution agreement, or made in connection with the tax opinion. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement.” In addition, under the separation and distribution agreement, we will also indemnify QEP and its remaining subsidiaries against various claims and liabilities relating to the past operation of our business. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Separation and Distribution Agreement.”

Dividend Policy

We anticipate paying quarterly dividends on our common stock. See “Dividend Policy.”

Transfer Agent

Wells Fargo Shareowner Services

Risk Factors

We face both general and specific risks and uncertainties relating to our business and our being an independent, publicly owned company. We also are subject to risks related to the spin-off. You should carefully read “Risk Factors” beginning on page 23 of this information statement.

SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL AND OPERATING DATA

The following table presents, in each case for the periods and as of the dates indicated, our summary historical combined financial and operating data and summary pro forma combined financial and operating data.

Our summary historical combined financial and operating data as of December 31, 2013 and 2012 and for the three years ended December 31, 2013, are derived from our audited combined financial statements included elsewhere in this information statement. Our summary historical combined financial and operating data as of March 31, 2014 and for the three months ended March 31, 2014 and 2013, are derived from our unaudited financial statements included elsewhere in this information statement. We have derived our balance sheet data for the year ended December 31, 2011, from our unaudited combined financial statements not included in this information statement.

The summary pro forma combined financial data presented in the following table for the year ended December 31, 2013, and as of and for the three months ended March 31, 2014 are derived from the unaudited pro forma combined financial data included elsewhere in this information statement. The pro forma combined financial data assumes that the transactions to be effected at the completion of the spin-off and described under “Summary—The Spin-Off” had taken place on March 31, 2014, in the case of the pro forma balance sheet, and as of January 1, 2013, in the case of the pro forma statement of income for the year ended December 31, 2013 and the three months ended March 31, 2014, respectively. These transactions primarily include, and the pro forma financial data give effect to the following:

•

QEP’s retention of the Haynesville Gathering System, which we will transfer to QEP in connection with the spin-off;

•

our entry into a new $ million revolving credit facility and the borrowing of $ million thereunder to fund a one-time dividend to QEP prior to the spin-off; and

•

the planned distribution by QEP of approximately shares of Entrada common stock to QEP stockholders.

The pro forma combined financial data does not give effect to the incremental annual general and administrative expenses that we expect to incur as a result of being an independent publicly traded company. We are in the process of determining the incremental general and administrative expenses that we expect to incur and will provide an estimated range in a later filing.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical combined financial statements and the notes thereto and our unaudited pro forma combined financial statements and the notes thereto, in each case included elsewhere in this information statement. 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 operated 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, the most directly comparable financial measure calculated in accordance with GAAP, please read “Selected Historical and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measures.” For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Business—Adjusted EBITDA.”


	QEPFS Historical															Entrada Pro Forma
	Year Ended December 31,									Three Months Ended March 31,						Three Months Ended March 31,	Year Ended December 31,
	2013⁽¹⁾			2012			2011			2014			2013			2014	2013
	(in millions, except per share and price information)
*Results of Operations*
Revenue	$	403.7		$	438.0		$	466.2		$	103.3		$	99.6
Operating income		172.0			206.1			252.0			39.3			46.8
Income from continuing operations		117.0			136.8			150.5			40.9			47.1
Net income attributable to us		105.0			133.1			147.3			22.4			29.5
Earnings per common share attributable to us
Basic
Diluted
Weighted-average common shares outstanding
Used in basic calculation
Used in diluted calculation
*Financial Position*
Total Assets	$	1,485.1		$	1,424.5		$	1,326.7		$	1,537.1
Capitalization
Long-term debt		—			199.5			254.8			—
Total equity		1,094.0			790.1			666.2			1,114.3

Total Capitalization	$	1,094.0		$	989.6		$	921.0		$	1,114.3

*Statement of Cash Flows*
Net cash provided by operating activities	$	118.2		$	232.1		$	269.7		$	23.8		$	91.9
Capital expenditures		(82.0	)		(166.3	)		(127.6	)		(13.5	)		(19.8	)
Net cash used in investing activities		(82.0	)		(166.3	)		(127.6	)		(13.5	)		(19.8	)
Net cash provided by (used in) financing activities		(18.1	)		(67.0	)		(140.9	)		(8.2	)		(70.0	)
*Non-GAAP Measures*
Adjusted EBITDA⁽²⁾	$	223.2		$	279.1		$	305.6		$	48.4		$	62.8
*Operating Information*
Gathering margin	$	163.0		$	172.7		$	161.0		$	34.4		$	39.2
Gas gathering volumes (in millions of MMBtu)		440.3			505.7			490.0			97.7			111.2
Average gas gathering revenue (per MMBtu)	$	0.35		$	0.34		$	0.33		$	0.34		$	0.35
Processing margin	$	127.8		$	146.3		$	185.8		$	37.2		$	35.6
Keep-whole margin	$	56.7		$	84.3		$	143.2		$	16.8		$	17.6
Gas processing volumes
NGL sales (Mbbl)		2,250.2			3,486.8			4,009.4			766.1			483.7
Average net realized NGL sales price (per bbl)	$	46.75		$	39.18		$	53.60		$	43.21		$	50.24
Fee-based processing volumes (in millions of MMBtu)		246.5			252.6			246.9			55.9			56.0
Average fee-based processing revenue (per MMBtu)	$	0.30		$	0.28		$	0.21		$	0.30		$	0.29

(1)

On August 14, 2013, we completed the initial public offering (“IPO”) of QEPM. Prior to the IPO, QEPM’s assets were wholly owned by us. Subsequent to the IPO, QEPM’s results are consolidated with our financial statements with the portion not owned by us reflected as noncontrolling interest. Refer to “Note 3—QEP Midstream Partners” in our audited financial statements included elsewhere in this information statement for detailed information on the IPO.

(2)	For a discussion of Adjusted EBITDA and a reconciliation to net income attributable to us, the GAAP measure most directly comparable to Adjusted EBITDA, please read “Selected Historical Financial and Pro Forma Combined Financial and Operating Data—Non-GAAP Financial Measures.”

You should carefully consider each of the risks described below, which we believe are the principal risks that we face and of which we are currently aware, and all of the other information included in this information statement. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations.

The natural gas and crude oil volumes that support our business depend on the level of production from the 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 gathering systems and processing, treating and fractionation facilities, new sources of natural gas and crude oil must be connected to our systems. 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 non-dedicated wells and (iii) our ability to compete successfully for volumes from sources connected to other systems.

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:

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, natural gas and NGL 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. Increases in natural gas prices and decreases in NGL prices could impact processing margins.

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 gathering systems and processing, treating and fractionation facilities, those reductions could reduce our revenue and cash flow and have a material adverse effect on our business, results of operations and financial condition.

We do not intend to obtain independent evaluations of oil and natural gas reserves connected to our gathering 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 and financial condition.

Our success depends on drilling activity and on 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 and financial condition.

We may not be able to increase our throughput and resulting revenue due to competition and other factors, which could limit our ability to grow.

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, 2013 and three months ended March 31, 2014, QEP accounted for approximately 35% and 28%, respectively, of our total revenue. Our ability to increase our gathering and processing 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 other shippers require it. To the extent that we lack available capacity on our systems for additional 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 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 and financial condition.

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 costs that could have a material adverse effect on our business, results of operations and financial condition. Additionally, our insurance coverage may be insufficient to cover adverse judgments against us.

We are the subject of ongoing litigation with Questar Gas Company (“QGC”), Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. Our former affiliate QGC filed its complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, an accounting and declaratory judgment related to a 1993 gathering agreement (“1993 Agreement”) executed when we and QGC were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of our systems provided gathering services to QCG and we charged an annual gathering rate that is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of QEPM’s IPO, the assets and the 1993 Agreement were assigned by us to QEPM. QGC netted the disputed amount from its monthly payments of the gathering fees to us and has continued to net such amounts from its monthly payments to QEPM. As of March 31, 2014, QEPM has deferred revenue of $9.9 million related to the QGC disputed amount. We have filed counterclaims seeking damages and declaratory judgment relating to our gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEPM as a defendant in the litigation. QEPM has been indemnified by QEP for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the omnibus agreement entered into between us, QEPM and QEP in connection with QEPM’s IPO. Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

XTO filed a complaint in Utah state court on January 30, 2014, XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the “XTO Agreement”). We process XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires us to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing our allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. XTO is seeking damages, but specific monetary damages have not been asserted.

Our business, results of operations and financial condition are affected by the volatility of oil, natural gas and NGL prices.

We are subject to significant risks associated with frequent and often substantial fluctuations in commodity prices. In the past, the prices of oil, natural gas and NGL have been volatile, and we expect this volatility to continue. The markets and prices for oil, natural gas and NGL depend upon factors beyond our control. These factors include the supply of and demand for oil, natural gas and NGL, which fluctuate with changes in market and economic conditions and other factors, including:

For the three months ended March 31, 2014, approximately 37% of our revenue was earned under commodity-based contracts that are directly affected by changes in NGL product prices and natural gas prices and thus are more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, our purchase and resale of NGL and natural gas in the ordinary course of business exposes us to significant risk of volatility in commodity prices due to the potential difference in the time of the purchases and sales and the potential existence of a difference in the commodity prices associated with each transaction. Significant declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets.

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

We compete with other 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 and processing, treating and fractionation facilities that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering systems and processing, treating and fractionation facilities 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 and financial condition.

We gather the oil and gather, process, treat or transport the natural gas and fractionate and transport the volumes of NGL on our assets 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, we are party to a gas conditioning agreement, or the Gas Conditioning Agreement, with QEPM whereby QEPM has agreed to make available to us at one or more of our processing complexes certain natural gas volumes that it has gathered pursuant to “life-of-reserves” and long-term agreements with producer customers. Pursuant to the terms of the Gas Conditioning Agreement, we have been assigned QEPM’s conditioning and processing rights in the underlying gathering agreements. If QEPM terminates the Gas Conditioning Agreement, which it may do at any time upon 30 days’ written notice, or QEPM amends an underlying gathering agreement (e.g. converting a “life-of-reserves” agreement to an annual agreement) or an underlying gathering agreement with QEPM is terminated or not renewed, that may have a material adverse impact on the volume of natural gas that we process. Our inability to renew our existing contracts on terms that are favorable to us or to successfully manage our overall contract mix over time may have a material adverse effect on our business, results of operations and financial condition.

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

Several of our gathering and processing agreements 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 oil or natural gas on our gathering systems or to process a minimum volume of natural gas at our processing complexes over certain periods during the term of the agreement. In addition, certain of our gathering and processing agreements also include an aggregate minimum volume commitment, which is a total amount of oil or natural gas that the customer must transport on our gathering systems or process natural gas at our processing complexes 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 or processing rate multiplied by the actual throughput volumes shipped or volumes processed.

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 or processed for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering or processing fee. To the extent that a customer’s actual throughput volumes or volumes processed are above or below its minimum volume commitment for the applicable period, several of our gathering and processing 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:

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 revenue or cash flows from one or more customers in a given period.

A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top two customers accounted for over 51% and 47% of our revenue for the year ended December 31, 2013 and the

three months ended March 31, 2014, respectively. We have contracts with each of these customers of varying duration and commercial terms. We incur expenses on behalf of our customers under certain contracts, and these customers have agreed to reimburse us for those expenses. 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 these customers in a timely fashion, on favorable terms or at all. QEP, Enterprise Products Operating, LP and EOG Resources, Inc. accounted for approximately 35%, 16% and 13%, respectively, of our revenue for the year ended December 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 business, results of operations and financial condition. 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 connected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the quality specifications of such pipelines or facilities, our business, results of operations and financial condition could be adversely affected.

Our gathering, processing and transportation systems connect to other pipelines or facilities owned and operated by third parties, such as the Kern River Gas Transmission Company Pipeline (“KRPL”), the Northwest Pipeline (“NWPL”), the Rockies Express Pipeline (“REX”) and others. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines 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 business, results of operations and financial condition could be adversely affected.

Certain of our assets have been in service for several decades. There could be increased maintenance or repair expenses and downtime associated with our assets that could have an adverse effect on our business, operating results and financial condition.

Certain of our gathering systems and processing plants have been in service for several decades. The age and condition of our pipeline systems and processing plants could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. For example, in April 2014 we shut down our Emigrant Trail Complex in order to conduct maintenance on its facilities, thereby causing us to process those natural gas volumes at our Blacks Fork Complex. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our assets could have an adverse effect on our business, results of operations and financial condition.

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 crude oil and the gathering, processing and treating of natural gas and in the fractionation of NGL, including:

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 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 any 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. 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.

Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.

We continuously consider and evaluate 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 share 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 experience 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.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Upon the closing of the spin-off, we expect to have $ million of total indebtedness and borrowing capacity of approximately $ million, calculated in accordance with the provisions of our Credit Facility. Our future level of debt could have important consequences for us, including the following:

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 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 hydrocarbons and the processing and treating of natural gas and the fractionation of NGL require 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 Credit Facility could adversely affect our business, financial condition and results of operations.

We intend to enter into the Credit Facility prior to the spin-off. The Credit Facility is likely to limit our ability to, among other things:

Our 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 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 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 stockholders could experience a partial or total loss of their investment.

We do not own all of the land on which our pipelines, plants and related facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines, plants and related facilities 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 and financial condition.

Certain of our facilities 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, or DOI, particularly the Bureau of Indian Affairs, Bureau of Land Management, or 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 natural gas production by our customers, which could adversely impact our revenue.

process is typically regulated by state oil and natural-gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted certain federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of natural gas that our customers produce, and could thereby adversely affect our revenue and results of operations

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 in the near- to medium- term is through organic growth projects. The construction of additions or modifications to our existing gathering systems and processing, treating and fractionation facilities 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 gathering systems and processing, treating and fractionation facilities, 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, processing 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 FERC; 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.

A substantial majority of our assets include gas-gathering facilities or interests in gas-gathering facilities. Natural gas gathering facilities are exempt from the jurisdiction of the FERC, under the Natural Gas Act of 1938 (“NGA”). Although the FERC has not made any formal determinations with respect to all of the facilities we

consider to be gathering 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 and processing, treating and fractionation facilities are subject to state regulation that could materially and adversely affect our operations and cash flows.

State regulation of gathering systems and processing, treating and fractionation facilities includes safety and environmental requirements. In addition, 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 revenue.

Two of QEPM’s pipelines are regulated by the FERC, which may adversely affect our revenue and results of operations.

QEPM owns an interstate gas pipeline company, Rendezvous Pipeline Company, L.L.C. (“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 indirectly affect our business, and could materially and adversely affect our revenue.

QEPM also owns 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 QEPM’s common carrier crude oil pipeline. As result of FERC regulation, QEPM may not be able to choose its customers or recover some of its costs of service allocable to such interstate transportation service, which may adversely affect our revenue and result of operations.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our natural gas gathering, processing and treating and NGL fractionation 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:

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 (“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 and the Hazardous Liquid Pipeline Safety Act of 1979, as amended by the Pipeline Safety Act of 1992 (the “PSA”), the Accountable Pipeline Safety and Partnership Act of 1996 (the “APSA”), the Pipeline Safety Improvement Act of 2002 (the “PSIA”), the Pipeline

Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), the Department of Transportation (“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:

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. We currently estimate that we will incur approximately $300,000 in costs during 2014 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. Effective October 25, 2013, PHMSA adopted new rules increasing 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 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 operating pressure and 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. 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.

The EPA also is beginning to adopt regulations controlling GHG emissions under its existing CAA authority. In response to its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA has adopted regulations that would restrict emissions of GHGs under existing provisions of the CAA that, among other things, establish monitoring and reporting requirements for large greenhouse gas emission sources, including for petroleum and natural gas facilities. 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 CAA. 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 derivative 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 (the “Dodd-Frank Act”), was enacted to establish federal oversight and regulation of the over-the-counter, or OTC, derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”), the SEC, and other regulatory authorities to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps entities, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, the reporting and recordkeeping of swaps, and expanded enforcement such as establishing position limits. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and we cannot yet predict the ultimate effect of the rules and regulations on our business.

The CFTC previously established position limits on certain core futures and equivalent swaps contracts in the natural gas and other markets, with exceptions for certain bona fide hedging transactions. The CFTC’s original position limits were vacated by a federal district court on September 28, 2012. On November 5, 2013, the CFTC proposed a new rulemaking on position limits and aggregation; however, it is uncertain at this time whether, when, and to what extent the CFTC’s position limits rules will become final and effective.

In December 2012, the CFTC published final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit swaps and setting compliance dates of March 11, 2013,

June 10, 2013, and, for commercial end-users of swaps, September 9, 2013. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps began in February 2014. Although we may qualify for the end-user exception from the mandatory clearing and trade execution requirements for our swaps entered into to hedge commercial risks, mandatory clearing and trade execution requirements applicable to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulatory authorities may require our counterparties to require that we enter into credit support documentation and/or post collateral; however, the proposed margin rules are not yet final, and therefore the application of those rules to us is uncertain at this time.

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. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.

We rely on highly skilled personnel and, if we are unable to retain or motivate key personnel, hire qualified personnel, or transfer knowledge from retiring personnel, our operations may be negatively impacted.

Our performance largely depends on the talents and efforts of highly skilled individuals. Our future success depends on our continuing ability to identify, hire, develop, motivate, and retain highly skilled personnel for all areas of its organization. Competition in the oil and gas industry for qualified employees is intense. Our continued ability to compete effectively depends on our ability to attract new employees and to retain and motivate our existing employees. We do not have employment agreements with or maintain key-man insurance for our key management personnel. The loss of services of one or more of our key management personnel could have a negative impact on our financial condition and results of operations.

In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees retire, we may not be able to replace them with employees of comparable knowledge and experience. Our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us and could negatively impact our business.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common stock.

Prior to the spin-off, we have not been required to file reports with the SEC. Upon the completion of the spin-off, 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 corporation. 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 (“Sarbanes-Oxley”), which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on 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, 2015.

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 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 stock.

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, the JOBS Act was signed into law. 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 Sarbanes-Oxley 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 revenue in a fiscal year, are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Exchange Act, which generally requires more than $700 million in market value of our common stock held by non-affiliates as of June 30 of the year such determination is made, 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 take advantage of this exemption and, therefore, will not 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 stock to be less attractive as a result, there may be a less active trading market for our common stock and our trading price may be more volatile.

We may not realize the benefits that we anticipate from our separation from QEP. These benefits include the following:

We may not achieve the anticipated benefits from our separation for a variety of reasons. For example, the process of separating our business from QEP and operating as an independent public company may distract our management from focusing on our business and strategic priorities. In addition, although we will have direct access to the debt and equity capital markets following the separation, we may not be able to issue debt or equity on terms acceptable to us or at all. The availability of shares of our common stock for use as consideration for acquisitions also will not ensure that we will be able to successfully pursue acquisitions or that the acquisitions will be successful. Moreover, even with equity compensation tied to our business we may not be able to attract and retain employees as desired. We also may not fully realize the anticipated benefits from our separation if any of the matters identified as risks in this “Risk Factors” section were to occur. If we do not realize the anticipated benefits from our separation for any reason, our business may be materially adversely affected.

The combined value of QEP and Entrada shares after the spin-off may not equal or exceed the value of QEP shares prior to the spin-off.

After the spin-off, QEP’s common stock will continue to be listed and traded on the NYSE under the symbol “QEP.” We intend to file an application to list our common stock on the NYSE under the symbol “EMID.” We cannot assure you that the combined trading prices of QEP common stock and Entrada common stock after the spin-off, as adjusted for any changes in the combined capitalization of these companies, will be equal to or greater than the trading price of QEP common stock prior to the spin-off. Until the market has fully evaluated the business of QEP without the midstream business, the price at which Entrada common stock trades may fluctuate significantly.

The historical and pro forma combined financial information that we have included in this information statement has been derived from QEP’s accounting records and may not necessarily reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods presented or those that we will achieve in the future. QEP did not account for us, and we were not operated, as a separate, stand-alone company for the historical periods presented. The costs and expenses reflected in our historical financial information include an allocation for certain corporate functions historically provided by QEP, including executive oversight, cash management and treasury administration, financing and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records management, real estate and facilities management, sourcing and procurement, mail, print and other office services, and other services, that may be different from the comparable expenses that we would have incurred had we operated as a stand-alone company. These allocations were based on what we and QEP considered to be reasonable reflections of the historical utilization levels of these services required in support of our business. We have not adjusted our historical or pro forma combined financial information to reflect changes that will occur in our cost structure and operations as a result of our transition to becoming a stand-alone public company, including changes in our employee base, potential increased costs associated with reduced economies of scale and increased costs associated with the SEC reporting and the NYSE requirements. Therefore, our historical and pro forma combined financial information may not necessarily be indicative of what our financial position, results of operations or cash flows will be in the future. For additional information, see “Selected Historical and Pro Forma Combined Financial and Operating Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes included elsewhere in this information statement.

Our costs may increase as a result of operating as a public company, and our management will be required to devote substantial time to complying with public company regulations.

We have historically operated our business as a segment of a public company. As a stand-alone public company, we may incur additional legal, accounting, compliance and other expenses that we have not incurred

historically. After the spin-off, we will become obligated to file with the SEC annual and quarterly information and other reports that are specified in Section 13 and other sections of the Exchange Act. We will also be required to ensure that we have the ability to prepare financial statements that are fully compliant with all SEC reporting requirements on a timely basis. In addition, we will also become subject to other reporting and corporate governance requirements, including certain requirements of the NYSE, and certain provisions of Sarbanes-Oxley and the regulations promulgated thereunder, which will impose significant compliance obligations upon us.

Sarbanes-Oxley, as well as new rules subsequently implemented by the SEC and the NYSE, have imposed increased regulation and disclosure and required enhanced corporate governance practices of public companies. We are committed to maintaining high standards of corporate governance and public disclosure, and our efforts to comply with evolving laws, regulations and standards in this regard are likely to result in increased marketing, selling and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. These changes will require a significant commitment of additional resources. We may not be successful in implementing these requirements and implementing them could materially adversely affect our business, results of operations and financial condition. In addition, if we fail to implement the requirements with respect to our internal accounting and audit functions, our ability to report our operating results on a timely and accurate basis could be impaired. If we do not implement such requirements in a timely manner or with adequate compliance, we might be subject to sanctions or investigation by regulatory authorities, such as the SEC or the NYSE. Any such action could harm our reputation and the confidence of investors and clients in our company and could materially adversely affect our business and cause our share price to fall.

Following the spin-off, for a period of time, we will continue to depend on QEP to provide us with certain services for our business; the services that QEP will provide to us following the separation may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with QEP expire.

Certain administrative services required by us for the operation of our business are currently provided by QEP and its subsidiaries, including services related to cash management and treasury administration, finance and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records management, real estate and facilities management, sourcing and procurement, mail, print and other office services. Prior to the completion of the spin-off, we will enter into agreements with QEP related to the separation of our business operations from QEP, including the Transition Services Agreement. We believe it is necessary for QEP to provide services for us under the Transition Services Agreement to facilitate the efficient operation of our business as we transition to becoming a stand-alone public company. We will, as a result, initially depend on QEP for services following the completion of the spin-off. While these services are being provided to us by QEP, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of the Transition Services Agreement, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from QEP under the Transition Services Agreement. Although we intend to replace portions of the services currently provided by QEP, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Transition Services Agreement.”

Our agreements with QEP require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.

We negotiated all of our agreements with QEP as a wholly owned subsidiary of QEP and will enter into these agreements prior to the completion of the spin-off. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the separation and distribution

agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the tax sharing agreement as described herein; see “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement”) related to our business, and we will agree to indemnify QEP for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between QEP and us may not reflect the allocation that would have been reached between two unaffiliated parties. See “Arrangements Between QEP and Our Company and Other Related Party Transactions” for a description of these obligations and the allocation of liabilities between QEP and us.

Our tax sharing agreement with QEP may limit our ability to take certain actions and may require us to indemnify QEP for significant tax liabilities.

Under the tax sharing agreement that we intend to enter into with QEP, we will agree to take reasonable action or reasonably refrain from taking action to ensure that the spin-off qualifies for tax-free status under Section 355 of the Code. We will also make various other covenants in the tax sharing agreement intended to ensure the tax-free status of the spin-off. These covenants may restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional common stock or other securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. For example, after the spin-off, we may not enter into any transaction that would cause us to undergo (or be deemed to undergo) either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock in transactions considered related to the spin-off. Moreover, certain of these restrictions may also apply to QEPM. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement.”

Further, under the tax sharing agreement, we may be required to indemnify QEP against certain tax-related liabilities incurred by QEP (including any of its subsidiaries) relating to the spin-off, to the extent caused by our breach of any representations or covenants made in the tax sharing agreement or the separation and distribution agreement, or made in connection with the tax opinion. These liabilities may include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of QEP) that would result if the spin-off of our stock to QEP’s stockholders failed to qualify as a tax-free transaction.

We will not have complete control over our tax decisions and could be liable for income taxes owed by QEP.

For any tax periods (or portion thereof) in which QEP owns at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries will be included in QEP’s consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of QEP or one or more of its subsidiaries for U.S. state or local income tax purposes. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement.”

Moreover, notwithstanding the tax sharing agreement, U.S. federal law provides that each member of a consolidated group is liable for the group’s entire tax obligation. Thus, to the extent QEP or other members of QEP’s consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of QEP’s consolidated group. Similar principles may apply for foreign, state or local income tax purposes where we file combined, consolidated or unitary returns with QEP or its subsidiaries for federal, foreign, state or local income tax purposes.

The spin-off will be conditioned upon, among other things, QEP’s receipt of an opinion of its tax counsel, Latham & Watkins LLP, reasonably acceptable to the QEP board of directors, substantially to the effect that the spin-off will be tax-free to QEP and QEP stockholders under Section 355 of the Code, except for cash payments made to QEP stockholders in lieu of fractional shares of Entrada common stock that such stockholders would otherwise receive in the distribution. The opinion will rely on certain facts, assumptions, representations and undertakings from QEP and us regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, QEP and its stockholders may not be able to rely on the opinion of its tax counsel and could be subject to significant tax liabilities. In addition, an opinion of counsel is not binding upon the Internal Revenue Service (the “IRS”), so, notwithstanding the opinion of QEP’s tax counsel, the IRS could conclude upon audit that the spin-off is taxable in full or in part if it disagrees with the conclusions in the opinion, or for other reasons, including as a result of certain significant changes in the stock ownership of QEP or us after the spin-off. If the spin-off is determined to be taxable for U.S. federal income tax purposes for any reason, QEP and/or its stockholders could incur significant income tax liabilities, and we could incur significant liabilities. For a discussion of the potential tax consequences to QEP stockholders if the spin-off is determined to be taxable, see “The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off.” For a description of the sharing of such liabilities between QEP and us, see “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement.”

Third parties may seek to hold us responsible for liabilities of QEP that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of QEP. Under our agreements with QEP, QEP will agree to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from QEP.

Our prior and continuing relationship with QEP exposes us to risks attributable to businesses of QEP.

QEP is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of QEP that are incurred through a breach of the separation and distribution agreement or any ancillary agreement by QEP or its affiliates other than us, or losses that are attributable to QEP in connection with the spin-off or are not expressly assumed by us under our agreements with QEP. Immediately following the spin-off, any claims made against us that are properly attributable to QEP in accordance with these arrangements would require us to exercise our rights under our agreements with QEP to obtain payment from QEP. We are exposed to the risk that, in these circumstances, QEP cannot, or will not, make the required payment.

Our directors and executive officers who own shares of common stock of QEP, who hold options to acquire common stock of QEP or other QEP equity-based awards, or who hold positions with QEP, may have actual or potential conflicts of interest.

Ownership of shares of common stock of QEP, options to acquire shares of common stock of QEP and other equity-based securities of QEP by certain of our directors and officers after the spin-off, and the presence of directors of QEP on our Board could create, or appear to create, potential conflicts of interest when those directors and officers are faced with decisions that could have different implications for QEP than they do for us. Certain of our directors may hold director positions with QEP or beneficially own significant amounts of common stock of QEP. See “Management.”

The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.

The spin-off is subject to review under various state and federal fraudulent conveyance laws. Under these laws, if a court in a lawsuit by an unpaid creditor or an entity vested with the power of such creditor (including without limitation a trustee or debtor-in-possession in a bankruptcy by us or QEP or any of our respective subsidiaries) were to determine that QEP or any of its subsidiaries did not receive fair consideration or reasonably equivalent value for distributing our common stock or taking other action as part of the spin-off, or that we or any of our subsidiaries did not receive fair consideration or reasonably equivalent value for incurring indebtedness, including the new debt incurred by us in connection with the spin-off, transferring assets or taking other action as part of the spin-off and, at the time of such action, we, QEP or any of our respective subsidiaries (i) was insolvent or would be rendered insolvent, (ii) had reasonably small capital with which to carry on its business and all business in which it intended to engage or (iii) intended to incur, or believed it would incur, debts beyond its ability to repay such debts as they would mature, then such court could void the spin-off as a constructive fraudulent transfer. If such court made this determination, the court could impose a number of different remedies, including without limitation, voiding our liens and claims against QEP, or providing QEP with a claim for money damages against us in an amount equal to the difference between the consideration received by QEP and the fair market value of our company at the time of the spin-off.

The measure of insolvency for purposes of the fraudulent conveyance laws will vary depending on which jurisdiction’s law is applied. Generally, however, an entity would be considered insolvent if the present fair saleable value of its assets is less than (i) the amount of its liabilities (including contingent liabilities) or (ii) the amount that will be required to pay its probable liabilities on its existing debts as they become absolute and mature. No assurance can be given as to what standard a court would apply to determine insolvency or that a court would determine that we, QEP or any of our respective subsidiaries were solvent at the time of or after giving effect to the spin-off, including the distribution of our common stock.

Under the separation and distribution agreement, from and after the spin-off, each of QEP and we will be responsible for the debts, liabilities and other obligations related to the business or businesses which it owns and operates following the consummation of the spin-off. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to QEP, particularly if QEP were to refuse or were unable to pay or perform the subject allocated obligations. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Separation and Distribution Agreement.”

No market currently exists for our common stock. We cannot assure you that an active trading market will develop for our common stock.

Prior to the completion of the spin-off, there has been no public market for shares of our common stock. We cannot predict the extent to which investor interest in our company will lead to the development of a trading market on the NYSE or otherwise, or how liquid that market might become. If an active market does not develop, you may have difficulty selling any shares of our common stock that you receive in the spin-off.

The market price and trading volume of our common stock may be volatile and you may not be able to sell your shares at or above the initial market price of our common stock following the spin-off.

The market price of our stock may be influenced by many factors, some of which are beyond our control, including those described above in “—Risks Related to Our Business” and the following:

As a result of these factors, holders of our common stock may not be able to sell their shares at or above the initial market price following the spin-off or may not be able to sell them at all. These broad market and industry factors may materially reduce the market price of our common stock, regardless of our operating performance. In addition, price volatility may be greater if the public float and trading volume of our common stock is low.

Future sales, or the perception of future sales, of our common stock may depress the price of our common stock.

Upon the completion of the spin-off, we will have approximately shares of common stock outstanding. The market price of our common stock could decline significantly as a result of sales of a large number of shares of our common stock in the market after the completion of the spin-off. The shares of our common stock that QEP distributes to its stockholders generally may be sold immediately in the public market. QEP stockholders could sell our common stock received in the distribution if we do not fit their investment objectives or, in the case of index funds, if we are not part of the index in which they invest. Sales of significant amounts of our common stock or a perception in the market that such sales will occur may reduce the market price of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Also, in the future, we may issue our securities in connection with investments or acquisitions. The amount of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding shares of our common stock.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

The future payment of dividends will be at the sole discretion of our Board and will be dependent on several factors. As a result, you may need to sell your shares of common stock to receive any income or realize a return on your investment.

Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law (the “DGCL”). The future payment of dividends will be at the sole discretion of our Board and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our Board deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of common stock. You may not be able to sell your shares of common stock at or above the price you paid for them.

Provisions of Delaware law and our charter documents may delay or prevent an acquisition of us that stockholders may consider favorable or may prevent efforts by our stockholders to change our directors or our management, which could decrease the value of your shares.

Section 203 of the DGCL and provisions in our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third-party to acquire us without the consent of our Board. See “Description of Capital Stock—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions.” These provisions include the following:

Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our direction or our management may be unsuccessful.

On , 2014, QEP announced that its board of directors approved pursuing a plan to separate QEP’s businesses into two stand-alone, publicly traded corporations through a distribution of 100% of our common stock to QEP stockholders. This authorization is subject to final approval by QEP’s board of directors, which approval is subject to, among other things, the conditions described below under “—Conditions to the Spin-Off.”

Following our spin-off from QEP, we will be an independent, publicly owned company. As part of the spin-off, we will transfer to QEP the assets and liabilities associated with our Haynesville Gathering System, and we will amend and restate our certificate of incorporation and bylaws.

To complete the spin-off, QEP will, following the restructuring transactions, distribute to its stockholders all of the shares of our common stock. The distribution will occur on the distribution date, which is , 2014. Each holder of QEP common stock will receive shares of our common stock for every shares of QEP common stock held by such stockholder at the close of business on , 2014, the record date. After completion of the spin-off, we will own and operate the midstream business.

Each holder of QEP common stock will continue to hold his, her or its shares in QEP. No vote of QEP stockholders is required or is being sought in connection with the spin-off, and QEP stockholders will not have any appraisal rights in connection with the spin-off, including the restructuring transactions.

The distribution of our common stock as described in this information statement is subject to the satisfaction or waiver of certain conditions. In addition, QEP has the right not to complete the spin-off if, at any time prior to the distribution, the board of directors of QEP determines, in its sole discretion, that the spin-off is not in the best interests of QEP or its stockholders or that market conditions are such that it is not advisable to separate us from QEP. For a more detailed description, see “—Conditions to the Spin-Off.”

QEP’s board of directors has determined that the spin-off is in the best interests of QEP and its stockholders because the spin-off will provide various benefits including: (1) focused management attention; (2) direct access to the debt and equity capital markets; (3) enhancing Entrada’s market recognition with investors; (4) improving Entrada’s ability to pursue acquisitions; (5) providing greater capital structure flexibility and (6) attracting volumes from third parties.

Focused management attention. Our midstream business and the exploration and production and marketing businesses of QEP have different financial and operating characteristics and as a result different operating strategies in order to maximize their long-term value. Our separation from QEP will allow QEP and us to focus managerial attention solely on our respective businesses and strategies and to better align management resources with the needs of our individual businesses. The dilution of attention involved in managing a combination of businesses with competing goals and needs will thus be eliminated. Our separate management teams will also be able to better prioritize the allocation of resources in support of differing priorities such as our desire to pursue our growth strategy through organic growth opportunities, third-party acquisitions and attracting additional third-party volumes to our systems, all of which require significant capital for which, as a part of QEP, we previously had to compete for with other QEP businesses.

Direct and differentiated access to the debt and equity capital markets. As a separate public company, we will no longer need to compete with QEP’s other businesses for capital resources. The midstream business is typically capital intensive throughout the business cycle and must continuously deploy significant amounts of capital to maintain operations and revenue growth. Both QEP and we believe that direct and differentiated access

to the capital markets will allow each of us to better optimize our capital structures to meet the specific needs of each of the respective businesses, aligning financial and operational characteristics with investor and market expectations.

Enhancing our market recognition with investors. QEP’s management and financial advisors believe that the investment characteristics of the midstream business and QEP’s other businesses may appeal to different types of investors. We believe our simpler corporate structure with a single business segment will allow us to fit more easily into a midstream investor sector and attract investors interested in focusing on the market dynamics, returns and informational inputs associated with a midstream company. The spin-off will improve the investment community’s visibility into and understanding of QEP’s and Entrada’s operations, particularly as each company is able to cultivate its own separate identity by providing more focused and targeted communication to the market regarding its own business strategies, assets, operational performance, financial achievements and management teams. After the spin-off, investors should be better able to evaluate the financial performance of QEP and us, as well as our respective strategies within the context of our respective market expectations and returns, thereby enhancing the likelihood that both entities will achieve appropriate market valuations.

Improving our ability to pursue acquisitions. As a stand-alone midstream company, we will be better positioned to use our equity securities as capital in pursuing merger and acquisition activities because the owners of the businesses we could seek to acquire will generally have greater interest in receiving securities of a company in the same line of business they were in rather than receiving the securities of a diversified operator of multiple businesses. However, we will be subject to certain requirements. For example, after the spin-off, we must avoid a 50% or greater change in our ownership in transactions related to the spin-off. This limitation is necessary in order to maintain the tax-free treatment of our separation from QEP. In addition, midstream entities generally trade at higher valuations than exploration and production companies. As such, Entrada’s higher-valued equity may enhance our competitiveness in pursuing acquisitions.

Capital structure. QEP has historically maintained a near-investment grade credit rating by keeping its leverage relatively low. Our peers typically operate with a greater amount of leverage than QEP’s exploration and production peer companies given their more stable, higher cash flow midstream operations. As an independent midstream company, we believe we will have greater capital structure flexibility and be able to maintain a leverage level that will allow us to competitively pursue strategic investment opportunities.

Third-party volumes. As an independent midstream company, we believe we will be able to attract additional throughput volumes from third-party exploration and production companies that would otherwise not be willing to dedicate volumes to us as a result of our affiliation with an exploration and production company. We believe these opportunities will increase the cash flow and ultimately the valuation of Entrada.

The general terms and conditions relating to the spin-off will be set forth in a separation and distribution agreement between us and QEP. Under the separation and distribution agreement, the distribution will be effective as of 11:59 p.m., Eastern time, on , 2014, the distribution date. As a result of the spin-off, on the distribution date, each holder of QEP common stock will receive shares of our common stock for every shares of QEP common stock that he, she or it owns. In order to receive shares of our common stock in the spin-off, a QEP stockholder must be a stockholder at the close of business of the NYSE on , 2014, the record date.

On the distribution date, QEP will release the shares of our common stock to our distribution agent to distribute to QEP stockholders. For most of these QEP stockholders, our distribution agent will credit their shares of our common stock to book-entry accounts established to hold their shares of our common stock. Our distribution agent will send these stockholders, including any QEP stockholder that holds physical share certificates of QEP common stock and is the registered holder of such shares of QEP common stock represented by those certificates on the record date, a statement reflecting their ownership of our common stock. Book-entry

refers to a method of recording stock ownership in our records in which no physical certificates are used. For stockholders who own QEP common stock through a broker or other nominee, their shares of our common stock will be credited to these stockholders’ accounts by the broker or other nominee. We expect that it will take the distribution agent one to two weeks to electronically issue shares of our common stock to QEP stockholders or their bank or brokerage firm by way of direct registration in book-entry form. Trading of our stock will not be affected by this delay in issuance by the distribution agent. As further discussed below, we will not issue fractional shares of our common stock in the distribution. Following the spin-off, stockholders whose shares are held in book-entry form may request that their shares of our common stock be transferred to a brokerage or other account at any time.

QEP stockholders will not be required to make any payment or surrender or exchange their shares of QEP common stock or take any other action to receive their shares of our common stock. No vote of QEP stockholders is required or sought in connection with the spin-off, including the restructuring transactions, and QEP stockholders have no appraisal rights in connection with the spin-off.

The distribution agent will not distribute any fractional shares of our common stock to QEP stockholders. Instead, as soon as practicable on or after the distribution date, the distribution agent will aggregate fractional shares of our common stock held by holders of record into whole shares, sell them in the open market at the prevailing market prices and then distribute the aggregate net sale proceeds ratably to QEP stockholders who would otherwise have been entitled to receive fractional shares of our common stock. The amount of this payment will depend on the prices at which the distribution agent sells the aggregated fractional shares of our common stock in the open market shortly after the distribution date. We will be responsible for any payment of brokerage fees. The amount of these brokerage fees is not expected to be material to us. The receipt of cash in lieu of fractional shares of our common stock will generally result in a taxable gain or loss to the recipient stockholder. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to the stockholder’s particular circumstances. The tax consequences of the distribution are described in more detail under “—U.S. Federal Income Tax Consequences of the Spin-Off.”

If you have any questions concerning the mechanics of the issuance of fractional shares of common stock held directly, we encourage you to contact Wells Fargo Shareowner Services using the contact information for Wells Fargo Shareowner Services set forth elsewhere in this information statement. If you have any questions concerning the mechanics of the issuance of fractional shares of common stock held in “street name,” we encourage you to contact your bank or brokerage firm.

The following is a summary of the material U.S. federal income tax considerations relating to QEP and to U.S. holders (as defined below) of shares of QEP common stock in connection with the distribution. This summary is based on the Code, the United States Treasury Regulations promulgated thereunder and judicial and administrative interpretations thereof, in effect as of the date hereof, and all of which are subject to change at any time, possibly with retroactive effect. Any such change could affect the tax consequences described below.

For purposes of this discussion, a U.S. holder is a beneficial owner of QEP common stock that is, for U.S. federal income tax purposes:

This summary does not discuss all tax considerations that may be relevant to holders in light of the particular circumstances, nor does it address the consequences to holders subject to special treatment under U.S. federal income tax laws, such as:

This summary also does not address the U.S. federal income tax consequences to QEP stockholders who do not hold shares of QEP common stock as a capital asset or to QEP stockholders who are not U.S. holders. Moreover, this summary does not address any state, local or foreign tax consequences or any estate, gift or other non-income tax consequences.

If a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes) holds shares of QEP common stock, the tax treatment of a partner in that partnership will generally depend on the status of the partner and the activities of the partnership. Partners in a partnership holding QEP common stock should consult their own tax advisors as to the tax consequences of the distribution.

QEP STOCKHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE UNITED STATES FEDERAL, STATE AND LOCAL AND NON-UNITED STATES TAX CONSEQUENCES OF THE DISTRIBUTION.

QEP expects to receive an opinion from its tax counsel, Latham & Watkins LLP, substantially to the effect that, for U.S. federal income tax purposes, the spin-off will be tax-free to QEP and QEP stockholders under Section 355 of the Code. Assuming the validity of the opinion, for U.S. federal income tax purposes:

U.S. Treasury regulations generally provide that if a QEP stockholder holds different blocks of QEP common stock (generally shares of QEP common stock purchased or acquired on different dates or at different prices), the aggregate basis for each block of QEP common stock purchased or acquired on the same date and at the same price will be allocated, to the greatest extent possible, between the shares of our common stock received in the distribution in respect of such block of QEP common stock and such block of QEP common stock, in proportion to their respective fair market values, and the holding period of the shares of our common stock received in the distribution in respect of such block of QEP common stock will include the holding period of such block of QEP common stock, provided that such block of QEP common stock was held as a capital asset on the distribution date. If a QEP stockholder is not able to identify which particular shares of our common stock are received in the distribution with respect to a particular block of QEP common stock, for purposes of applying the rules described above, the stockholder may designate which shares of our common stock are received in the distribution in respect of a particular block of QEP common stock, provided that such designation is consistent with the terms of the distribution. QEP stockholders are urged to consult their own tax advisors regarding the application of these rules to their particular circumstances.

Holders should note that the opinion that QEP expects to receive from its tax counsel, Latham & Watkins LLP, will be based on certain facts and assumptions, and certain representations and undertakings, from us and QEP, and is not binding on the IRS or the courts. If any of the facts, representations, assumptions or undertakings relied upon in the opinion is not correct, is incomplete or has been violated, our ability to rely on the opinion of counsel could be jeopardized. However, we are not aware of any facts or circumstances that would cause these facts, representations or assumptions to be untrue or incomplete, or that would cause any of these undertakings to fail to be complied with, in any material respect.

Even if the distribution otherwise qualifies under Section 355 of the Code, the distribution may result in corporate-level taxable gain to QEP under Section 355(e) of the Code if there is (or there is deemed to be) a 50% or greater change in ownership, by vote or value, of our stock or QEP’s stock (or any successor to us or QEP, which may include QEPM) occurring as part of a plan or series of related transactions that includes the

distribution. For this purpose, any acquisitions or issuances of QEP’s stock within two years before the distribution, and any acquisitions or issuances of our stock or QEP’s stock within two years after the distribution, are generally presumed to be part of such a plan, although we or QEP may be able to rebut that presumption. We are not aware of any acquisitions or issuances of QEP’s stock within the two years before the distribution that would be considered to occur as part of a plan or series of related transactions that includes the distribution. If an acquisition or issuance of our stock or QEP stock triggers the application of Section 355(e) of the Code, QEP would recognize taxable gain as described above and such gain would be subject to U.S. federal income tax.

If the distribution of shares of our common stock does not qualify under Section 355, then each U.S. holder of QEP receiving shares of our common stock in the distribution generally would be treated as receiving a distribution in an amount equal to the fair market value of such shares (including fractional shares in lieu of which such holder receives cash) of our common stock. This generally would result in the following consequences to the U.S. holder:

In addition, QEP would recognize a taxable gain equal to the excess of the fair market value of our common stock distributed to QEP shareholders on the distribution date over QEP’s adjusted tax basis in such stock, and, under certain circumstances, the tax sharing agreement would require us to indemnify QEP for such tax liability. See “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Tax Sharing Agreement.”

U.S. Treasury regulations require certain stockholders who receive stock in a distribution to attach to their U.S. federal income tax return for the year in which the distribution occurs a detailed statement setting forth certain information relating to the tax-free nature of the distribution. In addition, payments of cash to a U.S. holder of QEP common stock in lieu of fractional shares of our common stock in the distribution may be subject to information reporting and backup withholding (currently at a rate of 28%), unless the stockholder provides proof of an applicable exemption or a correct taxpayer identification number and otherwise complies with the requirements of the backup withholding rules.

Backup withholding does not constitute an additional tax, but merely an advance payment, which may be refunded or credited against a stockholder’s U.S. federal income tax liability, provided the required information is timely supplied to the IRS.

In connection with the distribution, we and QEP will enter into a Tax Sharing Agreement. The Tax Sharing Agreement will generally govern the respective rights, responsibilities and obligations of us and QEP with respect to tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes, non-income taxes and related tax returns. In addition, the Tax Sharing Agreement will contain certain restrictions on our ability to take actions that could cause the distribution to fail to qualify as a transaction that is generally tax-free. Additional details on the Tax Sharing Agreement will be provided in a subsequent amendment to the registration statement on Form 10 of which this Information Statement is a part.

THE FOREGOING IS A SUMMARY OF THE MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES OF THE DISTRIBUTION UNDER CURRENT LAW AND IS FOR GENERAL INFORMATION ONLY. THE FOREGOING DOES NOT PURPORT TO ADDRESS ALL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES OR TAX CONSEQUENCES THAT MAY ARISE UNDER THE TAX LAWS OR THAT MAY APPLY TO PARTICULAR CATEGORIES OF STOCKHOLDERS. EACH QEP STOCKHOLDER SHOULD CONSULT ITS OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF THE DISTRIBUTION TO SUCH STOCKHOLDER, INCLUDING THE APPLICATION OF U.S. FEDERAL, STATE, LOCAL AND FOREIGN TAX LAWS, AND THE EFFECT OF POSSIBLE CHANGES IN TAX LAWS THAT MAY AFFECT THE TAX CONSEQUENCES DESCRIBED ABOVE.

After the spin-off, we will be an independent, publicly owned company. Immediately following the spin-off, we expect to have approximately holders of shares of our common stock and approximately million shares of our common stock outstanding, based on the number of stockholders and outstanding shares of QEP common stock expected as of the record date. The figures assume no exercise of outstanding options and exclude shares of QEP common stock held directly or indirectly by QEP, if any. The actual number of shares to be distributed will be determined on the record date and will reflect any exercise of QEP options between the date the QEP board of directors declares the dividend for the distribution and the record date for the distribution.

For information regarding options to purchase shares of our common stock that will be outstanding after the distribution, see “Capitalization,” “Management,” “Security Ownership of Certain Beneficial Owners and Management” and “Arrangements Between QEP and Our Company and Other Related Party Transactions—The Separation from QEP—Employee Matters Agreement.”

Before the spin-off, we will enter into several agreements with QEP to effect the spin-off and provide a framework for our relationship with QEP after the spin-off. These agreements will govern the relationship between us and QEP after completion of the spin-off and provide for the allocation between us and QEP of QEP’s assets, liabilities and obligations. For a more detailed description of these agreements, see “Arrangements Between QEP and Our Company and Other Related Party Transactions.”

It is anticipated that, on or shortly before the record date and continuing up to and including the distribution date, there will be a “when-issued” market in our common stock. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The when-issued trading market will be a market for shares of our common stock that will be distributed to QEP stockholders on the distribution date. Any QEP stockholder that owns shares of QEP common stock at the close of business on the record date will be entitled to shares of our common stock distributed in the spin-off. QEP stockholders may trade this entitlement to shares of our common stock, without the shares of QEP common stock they own, on the when-issued market. On the first trading day following the distribution date, we expect when-issued trading with respect to our common stock will end and “regular-way” trading will begin. See “Trading Market.”

Following the distribution date, we expect shares of our common stock to be listed on the NYSE under the ticker symbol “EMID.” We will announce the when-issued ticker symbol when and if it becomes available.

ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if shares of QEP common stock are sold in the regular-way market up to and including the distribution date, the selling stockholder’s right to receive shares of our common stock in the distribution will be sold as well. However, if QEP stockholders own shares of QEP common stock at the close of business on the record date and sell those shares on the ex-distribution market up to and including the distribution date, the selling stockholders will still receive the shares of our common stock that they would otherwise receive pursuant to the distribution. See “Trading Market.”

We are in the process of determining the treatment of QEP equity-based compensation, and we will provide information regarding such treatment in an amendment to this information statement.

Prior to the spin-off, we will enter into the Credit Facility, which we expect will become effective on , 2014. We expect to have $ million of outstanding debt at the time of the spin-off.

We expect that the spin-off will be effective as of 11:59 p.m., Eastern time, on , 2014, the distribution date, provided that the following conditions shall have been satisfied or waived by QEP:

The fulfillment of the foregoing conditions will not create any obligation on QEP’s part to effect the spin-off. We are not aware of any material federal or state regulatory requirements that must be complied with or any material approvals that must be obtained, other than compliance with SEC rules and regulations and the declaration of effectiveness of the registration statement on Form 10 by the SEC, in connection with the distribution.

QEP has the right not to complete the spin-off if, at any time prior to the distribution, the board of directors of QEP determines, in its sole discretion, that the spin-off is not in the best interests of QEP or its stockholders or that market conditions are such that it is not advisable to separate us from QEP.

This information statement is being furnished solely to provide information to QEP stockholders that are entitled to receive shares of our common stock in the spin-off. This information statement is not, and is not to be construed as, an inducement or encouragement to buy, hold or sell any of our securities. We believe that the information in this information statement is accurate as of the date set forth on the cover. Changes may occur after that date and neither QEP nor we undertake any obligation to update the information except in the normal course of our respective public disclosure obligations.

There has been no public market for our common stock. An active trading market may not develop or may not be sustained. We anticipate that trading of our common stock will commence on a “when-issued” basis on or shortly before the record date and continue through the distribution date. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. When-issued trades generally settle within four trading days after the distribution date. If you own shares of QEP common stock at the close of business on the record date, you will be entitled to shares of our common stock distributed pursuant to the spin-off. You may trade this entitlement to shares of our common stock, without the shares of QEP common stock you own, on the when-issued market. On the first trading day following the distribution date, any when-issued trading with respect to our common stock will end and “regular-way” trading will begin. We intend to file an application list our common stock on the NYSE under the ticker symbol “EMID.” We will announce our when-issued trading symbol when and if it becomes available.

We also anticipate that, on or shortly before the record date and continuing up to and including the distribution date, there will be two markets in QEP common stock: a “regular-way” market and an “ex-distribution” market. Shares of QEP common stock that trade on the regular-way market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. QEP shares that trade on the ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if you sell shares of QEP common stock in the regular-way market up to and including the distribution date, you will be selling your right to receive shares of our common stock in the distribution. However, if you own shares of QEP common stock at the close of business on the record date and sell those shares on the ex-distribution market up to and including the distribution date, you will still receive the shares of our common stock that you would otherwise receive pursuant to the distribution.

We cannot predict the prices at which our common stock may trade before the spin-off on a “when-issued” basis or after the spin-off. Those prices will be determined by the marketplace. Prices at which trading in our common stock occurs may fluctuate significantly. Those prices may be influenced by many factors, including anticipated or actual fluctuations in our operating results or those of other companies in our industry, investor perception of our company and the midstream industry, market fluctuations and general economic conditions. In addition, the stock market in general has experienced extreme price and volume fluctuations that have affected the performance of many stocks and that have often been unrelated or disproportionate to the operating performance of the companies. These are just some factors that may adversely affect the market price of our common stock. See “Risk Factors—Risks Related to Our Common Stock.”

We expect that upon completion of the spin-off, we will have approximately million shares of common stock issued and outstanding, based on the number of shares of QEP common stock expected to be outstanding as of the record date. The shares of our common stock that you will receive in the distribution will be freely transferable, unless you are considered an “affiliate” of ours under Rule 144 under the Securities Act. Persons who can be considered our affiliates after the spin-off generally include individuals or entities that directly, or indirectly through one or more intermediaries, control, are controlled by, or are under common control with, us, and may include certain of our officers and directors. Immediately following the completion of the spin-off, we estimate that our officers and directors will hold shares of our common stock based on the number of shares of QEP common stock they hold on the record date. Our affiliates may sell shares of our common stock received in the distribution only:

In general, under Rule 144 as currently in effect, an affiliate will be entitled to sell, within any three-month period commencing 90 days after the date the registration statement, of which this information statement is a part, is declared effective, a number of shares of our common stock that does not exceed the greater of:

Sales under Rule 144 are also subject to restrictions relating to manner of sale and the availability of current public information about us.

In the future, we may adopt new stock option and other equity-based award plans and issue options to purchase shares of our common stock and other stock-based awards. We currently expect to file a registration statement under the Securities Act to register shares to be issued under these stock plans. Shares issued pursuant to awards after the effective date of the registration statement, other than shares issued to affiliates, generally will be freely tradable without further registration under the Securities Act.

Except for our common stock distributed in the distribution, none of our equity securities will be outstanding on or immediately after the spin-off and there are no registration rights agreements existing with respect to our common stock.

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2014, on an actual basis and pro forma basis to give effect to:

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

The following table presents, in each case for the periods and as of the dates indicated, our selected historical combined financial and operating data and selected pro forma combined financial and operating data.

Our selected historical combined financial and operating data as of December 31, 2013 and 2012, and for the three years ended December 31, 2013, are derived from our audited combined financial statements included elsewhere in this information statement. Our selected historical combined financial and operating data as of March 31, 2014 and for the three months ended March 31, 2014 and 2013, are derived from our unaudited financial statements included elsewhere in this information statement. We have derived our balance sheet data for the year ended December 31, 2011, from our unaudited combined financial statements not included in this information statement.

The selected pro forma combined financial data presented in the following table for the year ended December 31, 2013, and as of and for the three months ended March 31, 2014, are derived from the unaudited pro forma combined financial data included elsewhere in this information statement. The pro forma combined financial data assumes that the transactions to be effected at the completion of the spin-off and described under “Summary—The Spin-Off” had taken place on March 31, 2014, in the case of the pro forma balance sheet, and as of January 1, 2013, in the case of the pro forma statement of income for the year ended December 31, 2013 and the three months ended March 31, 2014, respectively. These transactions primarily include and the pro forma financial data give effect to the following:

The pro forma combined financial data does not give effect to incremental annual general and administrative expenses that we expect to incur as a result of being an independent publicly traded company. We are in the process of determining the incremental general and administrative expenses that we expect to incur and will provide an estimated range in a later filing.

We define Adjusted EBITDA as net income attributable to us before interest, income taxes, depreciation and amortization (“EBITDA”) adjusted to exclude gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items. Adjusted EBITDA is used as a supplemental financial measure by management and by external readers of our financial statements to assess:

We believe that the presentation of Adjusted EBITDA in this information statement provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income attributable to us. Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income, and these measures may vary among other companies. As a result, Adjusted EBITDA 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 us.

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 our historical combined financial statements and notes and our pro forma combined financial data included elsewhere in this information statement. 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 information statement.

We are currently a wholly owned subsidiary of QEP Resources, Inc., which is a holding company with three major lines of business: crude oil and natural gas exploration and production; midstream field services; and energy marketing. QEP had consolidated revenue for the year ended December 31, 2013 and three months ended March 31, 2014 in excess of $2.9 billion and $884.0 million, respectively, and trades on the New York Stock Exchange, or NYSE, under the symbol “QEP.” Following the spin-off, we will be an independent, publicly traded company. QEP will not retain any ownership interest in us.

We are a Delaware corporation that owns and operates a diversified portfolio of midstream energy assets. Our business primarily consists of providing natural gas gathering, processing, treating and transportation services and natural gas liquids, or NGL, fractionation and transportation services for our producer customers through our direct ownership and operation of two gathering systems and two processing complexes. In addition, we own a 60% interest in Green River Processing, which owns two processing complexes and one fractionation facility, with the remaining 40% interest owned by QEPM. Our assets, which are strategically located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado and the Uinta Basin located in eastern Utah provide critical infrastructure that links natural gas producers and suppliers to natural gas markets, including various interstate and intrastate pipelines. Finally, we own (i) an approximate 55.8% limited partner interest in QEP Midstream Partners, LP, a publicly traded crude oil and natural gas gathering partnership (NYSE: QEPM), consisting of 3,701,750 common units and 26,705,000 subordinated units and (ii) 100% of QEPM’s general partner, which owns the 2.0% general partner interest in QEPM and 100% of QEPM’s incentive distribution rights. In addition to the 40% interest in Green River Processing, QEPM’s assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which it provides natural gas and crude oil gathering and transportation services.

Our operations provide a full range of complementary midstream services, including gathering crude oil and natural gas at the wellhead, treating natural gas to meet downstream pipeline and customer quality standards, processing natural gas to separate the NGL from the natural gas, fractionating the resulting NGL into the various components and selling or delivering pipeline quality crude oil natural gas and NGL to various industrial and energy markets as well as interstate pipeline systems.

Our results are driven primarily by the volumes of crude oil and natural gas we gather, natural gas we process, the efficiency of our processing plants and fractionation facility, the commercial terms of our contractual

arrangements and commodity prices. Our contracts vary in duration and the pricing under our contracts varies depending upon several factors, including our competitive position, our acceptance of any risk associated with a longer-term contract and our desire to recoup over the term of the contract any capital expenditures that we are required to incur in order to connect a counterparty to our pipeline system.

Our management uses 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) gathering margin; (iii) processing margin; (iv) other operating expenses; and (v) Adjusted EBITDA.

The amount of gathering and processing revenue we generate primarily depends on the volumes of crude oil and natural gas that we gather and the volumes of natural gas we process for our customers. The volumes transported on our gathering and transportation pipelines and processed at our processing complexes are primarily affected by upstream development drilling and production volumes from the wells connected to our gathering and processing assets. 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 NGL, 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 correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to correlate with drilling activity.

Our gathering margin is dependent upon the amount of throughput in our systems and the gathering expenses we incur to operate our systems. We seek to maximize our gathering margin and our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, repair and non-capitalized maintenance costs, utilities and contract services comprise the most significant portion of our gathering expense. These gathering 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 variability and our operations and maintenance expenditures on our assets by scheduling maintenance throughout the year.

Our processing margin consists of both fee-based processing arrangements and keep-whole activities. The amount of fee-based revenue we generate is dependent upon the volumes of natural gas that are processed under these contracts through our processing complexes. Additionally, our keep-whole processing margin is the difference between our NGL product sales price, the purchase price of natural gas and transportation and fractionation costs. We seek to maximize our processing margin by minimizing, to the extent appropriate, expenses directly tied to operating our complexes. Direct labor costs, repair and non-capitalized maintenance costs, utilities and contract services comprise the most significant portion of our processing expense.

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

General and administrative. Our general and administrative expenses included both direct costs and costs allocated by QEP. Direct general and administrative costs include expenses such as professional services and

labor and benefits, including bonuses and share-based compensation. Costs allocated by QEP 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.

We anticipate incurring incremental general and administrative expenses attributable to operating as an independently publicly traded company, such as expenses associated with annual, quarterly and current reporting; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations 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 and we are in the process of determining the incremental general and administrative expenses that we expect to incur and will provide an estimated range in a later filing. Our future general and administrative expense will also include compensation expense associated with long-term incentive plans.

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 or units of production basis. We estimate our gathering and processing assets have useful lives ranging from 5 years to 40 years.

Adjusted EBITDA We define Adjusted EBITDA as net income attributable to us before interest, income taxes, depreciation and amortization (“EBITDA”), adjusted to exclude gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items. Adjusted EBITDA is used as a supplemental financial measure by management and by external readers of our financial statements to assess:

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.

Our operations are primarily dependent upon natural gas production from the upstream sector. The decline in natural gas prices from the levels seen in the mid 2000’s 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 producers in exploration for and development of new natural gas reserves.

A portion of our operations are based on keep-whole processing agreements. Under our keep-whole processing agreements, we are exposed to the spread between NGL product sales price and the purchase price of natural gas. In recent years U.S. exploration & production companies have shifted capital to liquids-rich gas areas and caused NGL production to increase dramatically. Increased NGL production, several warmer-than-average winters, and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening in NGL prices, particularly ethane. We expect that ethane prices will continue to be range-bound until new crackers are built; however, the prices of heavier components of the NGL barrel have strengthened as a result of recent weather conditions combined with newly commissioned export projects.

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. Under some of our contracts, we are able 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 cost increases. To the extent we are unable to procure necessary supplies or recover higher costs, our financial and operating results will be negatively impacted.

Interest rates have been relatively low in recent periods. If interest rates rise, our future financing costs will increase accordingly.

The regulation of crude oil and natural gas gathering, transportation and processing activities by FERC, and other federal and state regulatory agencies, including the 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 crude oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of crude 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.”

Our future results of operations will not be comparable to our historical results of operations for the reasons described below.

Our results of operations historically included revenue and expenses related to our Haynesville Gathering System. We will transfer the Haynesville Gathering System to QEP in the connection with this spin-off.

We anticipate incurring incremental general and administrative expenses attributable to operating as an independent publicly traded corporation, such as expenses associated with annual, quarterly and current reporting; 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. We are in the process of determining the incremental general and administrative expenses that we expect to incur and will provide an estimated range in a later filing. For the year ended December 31, 2013 and the three months ended March 31, 2014, we incurred $47.5 million and $14.5 million in general and administrative expenses, respectively.

The impacts of our related party transactions have historically 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 related party 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.

In certain periods prior to the spin-off, we had intercompany debt with QEP and incurred interest expense on this intercompany debt. These balances were paid off as of December 31, 2013. As a result, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in the future. Prior to the spin-off, we also intend to enter into a revolving credit facility, and we expect to incur interest expense at customary short-term interest rates.

During the year ended December 31, 2013, we completed QEPM’s IPO. Prior to the IPO, QEPM’s assets were wholly owned by us. Subsequent to the IPO, QEPM’s results are consolidated in our financial statements, with the portion not owned by us reflected as noncontrolling interest. Refer to “Note 3—QEP Midstream Partners” in our audited financial statement included elsewhere in this information statement for detailed information on the IPO.

The following tables are a summary of our financial and operating results from gathering activities:

Three Months Ended March 31, 2014 compared to Three Months Ended March 31, 2013

During the first quarter of 2014, gathering margin declined 12% compared to the first quarter of 2013 primarily due to a 14% decrease in gathering revenue and a 3% increase in gathering expense, partially offset by an 8% increase in other gathering revenue. The decrease in gathering revenue was a result of a 12% decrease in gathering system throughput primarily driven by a 41% decline on the Haynesville Gathering System due to lower production by QEP Energy resulting from the continued suspension of drilling in Haynesville, and lower gathering volumes on the Uinta Basin Gathering System and QEPM’s Vermillion Gathering System. The increase in gathering expense was primarily the result of increased labor and benefits costs due to additional compensation costs from QEP’s annual incentive program. The increase in other gathering revenue was primarily related to higher deficiency revenue associated with minimum volume commitments under our gathering agreements at QEPM’s Williston Gathering System. QEPM’s Green River Gathering Assets, our Uinta Basin Gathering System and our Haynesville Gathering System accounted for 48%, 17% and 12%, respectively, of the total gathering system throughput during the first three months of 2014.

During the year ended December 31, 2013, gathering margin declined 6% compared to December 31, 2012, primarily due to a 11% decrease in gathering revenue and an 8% increase in gathering expense, partially offset by a 33% increase in other gathering revenue. The decrease in gathering revenue was a result of decreased gathering system throughput volumes of 65.4 million MMBtu, or 13%. This decrease primarily related to a 43% decline in throughput on the Haynesville Gathering System due to lower production by QEP Energy resulting from the suspension of drilling in the Haynesville shale. In addition, gathering system throughput decreased 11% on QEPM’s Vermillion Gathering System due to lower volumes from third parties. The increase in gathering expense was primarily the result of increased labor and benefits costs due to additional compensation costs from QEP’s annual incentive program. The increase in other gathering revenue was primarily related to deficiency revenue recognized associated with minimum volume commitments under our gathering agreements related to the Uinta Basin Gathering System and Williston Gathering System. The Green River Gathering Assets, our Uinta Basin Gathering System and our Haynesville Gathering System accounted for 47%, 17% and 15%, respectively, of the total gathering system throughput during 2013.

During the year ended December 31, 2012, our gathering margin increased 7% compared to December 31, 2011, primarily due to an increase in gathering revenue and other gathering revenue of 7%, partially offset by an

increase in gathering expense of 5%. The increase in gathering revenue was a result of a 3% increase in gathering system throughput volume and a 3% increase in average gas gathering revenue per MMBtu during 2012. The 15.7 million MMBtu increase in gathering volumes was mainly related to increased gathering volumes on the Haynesville Gathering System and the Green River Gathering Assets, which were 12% and 8% higher, respectively, during 2012. The Green River Gathering Assets, Uinta Basin Gathering System and Haynesville Gathering System accounted for 40%, 16% and 23%, respectively, of the total gathering system throughput during 2012.

The following table provides a summary of our financial and operating results from processing activities:

We provide gas processing services under fee-based and keep-whole agreements. Under keep-whole arrangements, we process natural gas, sell the resulting NGL at market prices, and remit the natural gas energy equivalent value to our customers. Because the extraction of NGL from the natural gas during processing reduces the Btu content of the natural gas, we must acquire natural gas at market prices to return the energy equivalent value to our customers. Accordingly, under these arrangements our revenue and margins increase as the price of NGL increases relative to the price of natural gas and decrease as the price of NGL decreases relative to the price of natural gas.

Three Months Ended March 31, 2014 compared to Three Months Ended March 31, 2013

Our keep-whole margin decreased by 5% during the first quarter of 2014 compared to the first quarter of 2013, primarily due to higher processing plant fuel and shrinkage expense and NGL transportation and fractionation costs, partially offset by an increase in NGL sales. Processing plant fuel and shrinkage expense increased due to higher natural gas prices and NGL transportation and fractionation costs increased due to increased NGL sales volumes. NGL sales increased as a result of a 58% increase in NGL sales volumes, partially offset by a 14% decrease in average net realized NGL sales price. The increase in NGL sales volumes is the result of the 155 MMcf/d Iron Horse II processing plant at the Uinta Basin Complex in eastern Utah operating during the entire first quarter of 2014 (start-up in late first quarter of 2013) and a linefill cash-out due to a contractual change in the first quarter of 2014. Also contributing to the higher NGL sales was an increase in the average net realized NGL sales price due to the higher propane prices and completion of the Blacks Fork fractionation and loading facility expansion, which increased the volumes that we could sell into local and regional markets. Average net realized NGL prices decreased by 14% in the first quarter of 2014, primarily the result of ethane sold through the cash out of line fill.

Fee-based processing revenue increased slightly during the first quarter of 2014 compared to the first quarter of 2013 due to a 3% increase in average fee-based processing rates partially offset by a decrease in fee-based processing volumes. During the first quarter of 2014, the decrease in fee-based processing volumes was the result of a reduction in gas processed at the Emigrant Trail Complex and the Blacks Fork Complex, offset by an increase at the Uinta Basin Complex. The increase in the average fee-based processing rate was due to the annual escalation of processing fees. Approximately 80% and 76% of our net operating revenue was derived from fee-based gathering and processing agreements in the first quarter of 2014 and 2013, respectively.

During the year ended December 31, 2013, our keep-whole processing margin decreased 33% compared to 2012 primarily due to a 35% decrease in NGL sales volumes. The decrease in NGL sales volumes was the result of not recovering ethane on keep-whole volumes. Partially offsetting this decline was an increase in the average net realized NGL sales price. Including the impact of gains on derivative contract settlements, average NGL realized prices increased 19% during 2013, primarily the result of the rejection of ethane, which is the lower-value component of the composite NGL barrel. In addition, keep-whole margin was positively impacted in 2013 by an $11.0 million decrease in NGL transportation and fractionation costs due to the reduction in NGL volumes in 2013.

Fee-based processing revenue increased 6% during the year ended December 31, 2013, compared to 2012 primarily due to a 7% increase in the average fee-based processing rate partially offset by a 2% decrease in fee-based processing volumes. Approximately 82% and 76% of our net operating revenue was derived from fee-based gathering and processing agreements in the years ended December 31, 2013 and 2012, respectively.

During the year ended December 31, 2012, our keep-whole processing margin decreased 41% compared to 2011 primarily due to a 36% decrease in NGL sales and higher NGL transportation and fractionation costs. Including the impact of gains on derivative contract settlements, NGL prices decreased 27% in 2012 and NGL sales volumes decreased 13% in 2012. The decrease in NGL sales volumes was primarily the result of the execution of a fee-based processing agreement with QEP in the Uinta Basin that effectively transferred NGL barrels from us to QEP in the second quarter of 2012, partially offset by the Black Fork II plant completion, which commenced operations in July 2011. Transportation and fractionation costs were $15.3 million higher during the year ended December 31, 2012, compared to 2011, which was the result of additional transportation costs relating to NGL sale agreements that provide for transportation and fractionation of NGL at Mont Belvieu, Texas, and the full year operation of the Blacks Fork II plant.

Fee-based processing revenue increased 33% during the year ended December 31, 2012, primarily due to a 33% increase in the average fee-based processing rate and a 2% increase in fee-based processing volumes. The increased processing volume during the year ended December 31, 2012, was primarily the result of the start-up of the 155 MMcf/d Iron Horse I processing plant at the Uinta Basin Complex during the first quarter of 2011 and the start-up of the Blacks Fork II plant. Approximately 76% and 64% of net operating revenue was derived from fee-based gathering and processing agreements in the years ended December 31, 2012 and 2011, respectively.

Periodically, we purchase and resell gas and NGL to third parties and QEP’s other subsidiaries for various business purposes. During the three months ended March 31, 2014, QEP had a net gain from condensate resale transactions of $0.5 million. During the year ended December 31, 2013 and 2012, QEP had a net loss of $0.4 million and a net gain of $1.2 million, respectively, related to various resale transactions.

Three Months Ended March 31, 2014 compared to Three Months Ended March 31, 2013

General and administrative expense. During the first quarter of 2014, general and administrative (“G&A”) expense increased $3.7 million, or 34%, compared to the first quarter of 2013. The increase in G&A in 2014 was primarily due to a $2.3 million increase for the accrual of retention bonuses related to the spin-off to be paid upon the earlier of December 2014 or whenever the spin-off occurs, and an increase in professional and outside services mainly related to the ongoing implementation of a new Enterprise Resource Planning (“ERP”) system and current transactions, including the spin-off and QEPM operating as a public company.

Depreciation and amortization. During the first three months of 2014, depreciation and amortization expense increased $0.8 million, or 5%, compared to the first three months of 2013. This increase was the result of the addition of the Iron Horse II processing plant at the Uinta Basin Complex operating during the entire first quarter of 2014 (start-up in late first quarter of 2013).

Income from unconsolidated affiliates. In the first three months of 2014, income from unconsolidated affiliates was higher by $0.9 million, or 69%, compared to the first three months of 2013, primarily due to increased income from Three Rivers Gathering due to increased deficiency revenue recognized in the first quarter of 2014.

Interest expense, net. Interest expense decreased $0.7 million, or 54%, during the first quarter of 2014 compared to the first quarter of 2013. The decrease was due to the elimination of intercompany debt as of December 31, 2013. Interest expense in the first quarter related to commitment fees and deferred financing costs associated with QEPM’s credit facility.

Income taxes. Income tax provision was $12.8 million during the first quarter of 2014 compared to an income tax provision of $17.0 million during the first quarter of 2013. The decreased provision was primarily the result of lower income before income taxes for the first quarter of 2014 compared to 2013 and a lower combined effective federal and state income tax rate of 31.1% during the three months ended March 31, 2014, compared to 36.0% for the three months ended March 31, 2013.

General and Administrative. During 2013, G&A expense increased $12.2 million, or 35%, compared to 2012. The increase in G&A in 2013 was primarily due to increased legal and professional services expenses in 2013 related to the QEPM IPO transaction, QEPM operating as a public company (see “Note 3—QEP Midstream

Partners”), the implementation of a new ERP system and the QGC litigation (see “Note 10—Commitments and Contingencies”). Additionally, there was an increase in labor costs due to an increased number of employees, the Company’s annual compensation program and our retention plan (see “Note 8—Restructuring Costs”, all notes are included in our audited financial statement included elsewhere in this information statement).

Depreciation and amortization. Depreciation and amortization expense was consistent during the year ended 2013 compared to 2012 as a result of asset additions in 2013 offset by changes in the unit of production rates.

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $6.1 million for the year ended December 31, 2013, decreasing $1.1 million from 2012. Income from Three Rivers Gathering was $2.8 million in 2013 compared to $3.5 million in 2012 and income from Uintah Basin Field Services was $3.3 million in 2013 compared to $3.7 million in 2012.

Realized gain on derivative contracts. Gains and losses on derivative instruments are comprised of realized gains on commodity derivative contracts. During the year ended December 31, 2013, we had no commodity derivative instruments. During 2012, we had realized gains on commodity derivative instruments of $8.4 million.

Interest expense, net. Interest expense decreased $7.8 million, or 72%, during the year ended December 31, 2013, compared to 2012. The decrease was attributable to average debt levels that were approximately $127.4 million, or 56%, lower than average debt levels in 2012. The decrease in average debt levels is primarily related to the settlement of intercompany debt with QEP in 2013, resulting in no debt outstanding as of December 31, 2013.

Income taxes. Income tax provision decreased $14.9 million, or 20%, during the year ended December 31, 2013, compared to 2012. The decrease was primarily the result of lower income before income taxes and a lower combined effective federal and state income tax rate of 33.6% during the year ended December 31, 2013, compared to 35.1% for the year ended December 31, 2012.

General and Administrative. G&A expenses increased by $1.4 million during the year ended December 31, 2012, compared to 2011 primarily related to increased labor and benefits expenses due to an increased number of employees and the Company’s annual compensation program and higher professional services related to the implementation of a new ERP system.

Depreciation and amortization. Depreciation and amortization expense increased by $8.8 million, or 16%, from 2011. The increase was primarily attributable to a $4.8 million increase at our Blacks Fork Complex due to the Blacks Fork II plant completion, which commenced operations in July 2011, and a $1.5 million increase at our Uinta Basin Complex the result of the start-up of the Iron Horse I processing plant during the first quarter of 2011, both of which were depreciated on the units of production basis. Other increases were attributable to the Williston Gathering System and Haynesville Gathering System due to asset additions in 2012.

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased by $2.8 million or 64% from 2011. Income from Three Rivers Gathering was $3.5 million in 2012 compared to $1.9 million in 2011 and income from Uintah Basin Field Services was $3.7 million in 2012 compared to $2.5 million in 2011.

Realized gain on derivative contracts. Effective January 1, 2012, we discontinued hedge accounting. As a result, changes during the year ended December 31, 2012 are recognized in current period earnings. During 2012, we had realized gains on commodity derivative instruments of $8.4 million.

During the year ended December 31, 2011, we used hedge accounting and changes in the mark-to-market value of the commodity derivative contracts were reflected in accumulated other comprehensive income (“AOCI”) and ultimately recognized as revenue when the commodity derivatives were settled. As a result of

discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in AOCI as of the de-designation date and were reclassified into our Combined Statement of Operations as the transactions settled and impact earnings.

Interest expense, net. Interest expense decreased $5.9 million, or 35%, during the year ended December 31, 2012, compared to 2011. The decrease in interest expense during 2012 was due to average debt levels that were approximately $102.0 million lower than average debt levels during 2011. The decrease in average debt levels is related to lower intercompany debt balances with QEP year over year.

Income taxes. Income tax provision decreased $15.1 million, or 17%, during the year ended December 31, 2012, compared to 2011. The decrease was primarily the result of lower income before income taxes and a lower combined effective federal and state income tax rate of 35.1% during the year ended December 31, 2012, compared to 37.2% during 2011. The 2012 combined rate was lower due to state income tax adjustments to prior year provisions based on tax returns filed.

Historically, our sources of liquidity include cash generated from operations and funding from QEP. We historically participated in QEP’s centralized cash management program under which the net balance of our cash receipts and cash disbursements were settled with QEP on a periodic basis. Following the spin-off, we will maintain our own bank accounts and sources of liquidity. Our ongoing sources of liquidity to meet operating expenses and fund capital expenditures include cash generated from operations, borrowings under our new revolving credit facility, and access to debt and equity markets. 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.

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

Three Months Ended March 31, 2014 compared to Three Months Ended March 31, 2013

Operating Activities. The primary components of net cash provided from operating activities are changes in working capital, non-cash adjustments to net income and net income and are presented in the following table:

Investing Activities. Our historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. Our historical capital expenditures are presented in the following table:

In the first quarter of 2014 compared to the first quarter of 2013, our capital investment increased by $12.8 million, on an accrual basis. Capital expenditures during the first quarter of 2014 primarily related to the expansion of the Uinta Basin Gathering System and the expansion of the Vermillion Complex, with the remaining expenditures relating to maintenance capital expenditures and other minor projects on the various plants and gathering systems.

Financing Activities. In the first quarter of 2014, net cash used in financing activities was $8.2 million compared to $70.0 million in the first quarter of 2013. During the first quarter of 2014, we made a cash distribution on behalf of QEPM of $6.0 million, or $0.26 per unit, to public common unitholders, and $1.6 million to owners of noncontrolling interests in our assets. Additionally, we had a cash distribution to QEP for $0.6 million. During the first quarter of 2013, we repaid long-term debt to QEP of $60.4 million and paid an additional distribution to QEP of $6.4 million. Lastly, we paid a $1.5 million distribution to owners of noncontrolling interests in our assets.

Year Ended December 31, 2013 compared to Year Ended December 31, 2012 and Year Ended December 31, 2012 compared to Year Ended December 31, 2011

Financing Activities. During the year ended December 31, 2013, net cash used in financing activities was $18.1 million compared to $67.0 million during the year ended December 31, 2012. During the year ended December 31, 2013, we had net proceeds from the QEPM IPO of $449.6 million, which was used to repay long-term debt to QEP of $199.5 million, pay revolving credit origination fees of $3.2 million, and make a cash distribution to QEP for $16.0 million. Additionally, we made a cash dividend payment to QEP for $238.0 million. Lastly, we paid distributions on behalf of QEPM of $3.0 million, or $0.13 per unit to the 23,008,998 outstanding limited partner common units owned by the public, and $6.3 million to owners of noncontrolling interests in our assets.

During the year ended December 31, 2012, net cash used in financing activities was $67.0 million compared to $140.9 million during the year ended December 31, 2011. During 2012, we repaid long-term debt to QEP of $55.3 million, received a contribution from QEP of $6.8 million and paid a distribution of $6.6 million to owners of non-controlling interests in our assets. During 2011, we repaid long-term debt to QEP of $148.7 million, received a contribution from QEP of $13.3 million and paid a distribution of $5.4 million to owners of non-controlling interests in our assets.

In connection with the spin-off, we expect to enter into a new credit facility (“Credit Facility”), which will be $ million revolving credit facility. Upon completion of the spin-off, we expect to have $ million of borrowing capacity under our credit 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. As the terms of the credit agreement governing the Credit Facility are finalized, we will provide the required and appropriate information in subsequent amendments to the Form 10 to which this information statement is an exhibit.

Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include commercial and industrial enterprises that may react differently to changing conditions. Our principal customer for our natural gas gathering, processing, treating and fractionation 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, late payment, or non-performance by our customers, including QEP 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 QEP provides a signification portion of our revenue. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

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, 2013:

QEPFS provides crude oil and gas gathering, processing, treating and transportation services, NGL, fractionation and marketing services to QEP resulting in related party transactions. We believe that the terms and conditions under these agreements are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services in the ordinary course of its business. QEPFS has entered into agreements with QEP including operating agreements and other service agreements. For the three months ended March 31, 2014 and 2013, approximately 31% and 40%, respectively, of our revenue came from QEP. For the twelve months ended December 31, 2013, 2012 and 2011, approximately 40%, 37% and 27%, respectively, of our revenue came from QEP. Refer to “Note 4—Related Party Transactions” in our audited financial statements included elsewhere in this information statement for additional information on related party transactions.

The following discussion relates to the critical accounting policies and estimates applicable to us. Our combined financial statements are prepared in accordance with GAAP. The preparation of combined 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.

We use the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. The investment in unconsolidated affiliates on our combined balance sheets equals our 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 our 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 our ownership percentage as of December 31, 2013, 2012 and 2011 were Uintah Basin Field Services, L.L.C in which we owned a 38% ownership, and Three Rivers Gathering, L.L.C. in which QEPM currently owns a 50% ownership interest, which was previously owned by us

prior to QEPM’s initial public offering (see “Note 3—QEP Midstream Partners” in our audited financial statement included elsewhere in this information statement). Both are limited liability companies engaged in the gathering and compressing of natural gas.

The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenue, 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, income taxes, valuation of derivatives instruments, 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.

We provide gathering services, primarily under fee-based contracts, as well as processing services, under keep-whole and fee-based contracts. Under fee-based arrangements, we receive a fee or fees for one or more of the following services: firm and interruptible gathering of crude oil and natural gas or processing of natural gas. The revenue we earn from the fee-based arrangements is generally directly related to the volume of oil or gas that flows through our systems or complexes and is not directly dependent on commodity prices. A portion of the fee-based agreements provide for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms.

Under keep-whole arrangements, we process the natural gas for a customer and take title to the resulting NGL, which is sold to third parties at market prices. Because the extraction of the NGL from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this gas. In addition, under the majority of our agreements, we retain and sell condensate that falls out of the natural gas stream during gathering and processing. Additionally, we have 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 primarily consists of natural gas and oil gathering pipelines, transmission pipelines, compressors and processing, treating and fractionation facilities and are stated at the lower of historical cost, less accumulated depreciation or fair value, if impaired. We capitalize 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. Assets placed into service are depreciated, on a straight-line-basis or units of production method, over the estimated useful life of the asset.

We evaluate whether long-lived assets have been impaired and determine if the carrying amount of the assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the estimated fair value of an evaluated asset is less than the asset’s carrying value. If impairment is indicated, the asset would be reduced to the estimated fair value. There were no long-lived asset impairments during 2013, 2012 or 2011.

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 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 ARO 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.

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. We regularly review contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. See “Note 10—Commitments and Contingencies” in our audited financial statement included elsewhere in this information statement for additional information.

We accrue 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.

Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. We record interest earned on income tax refunds in interest and other income and records penalties and interest charged on tax deficiencies in interest expense.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that our recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or end of the twelve-month periods ended December 31, 2013, 2012 and 2011. Federal income tax returns for 2011 and 2012 are closed by the Internal Revenue Service. Income tax returns for 2013 have not yet been filed. Most state tax returns for 2010 and subsequent years remain subject to examination.

Noncontrolling interests represent third-party ownership in the net assets of our combined subsidiaries and are presented as a component of equity and net income. Changes in our ownership interest in subsidiaries that do not result in deconsolidation are recognized in equity. On August 14, 2013, QEP completed the initial public offering of QEPM. Prior to the IPO, QEP’s noncontrolling interest related to the outside ownership of Rendezvous Gas Services, L.L.C. Subsequent to the IPO, QEPM’s results (which include Rendezvous Gas Services, L.L.C) are consolidated into our financial statements as it is a majority-owned and controlled subsidiary and the portion not owned by us, reflected as noncontrolling interest. See “Note 3—QEP Midstream Partners” in our audited financial statement included elsewhere in this information statement for further information regarding the IPO.

During the year ended December 31, 2013, there were no new accounting pronouncements that were applicable to us.

At March 31, 2014, we had no debt outstanding. In 2013, we had a promissory note with QEP with a fixed rate of 6.05% that was not subject to interest rate movements. This debt was settled on December 31, 2013. We anticipate that our new Credit Facility will contain a variable interest rate that exposes us to volatility in interest rates.

We are exposed to the impact of market fluctuations in the prices of natural gas, NGL and condensate. Both our profitability and our cash flow are affected by volatility in the prices of these commodities. Natural gas and NGL prices are impacted by changes in the supply and demand for these products, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Natural gas prices, can also affect our profitability indirectly by influencing the level of drilling activity in our areas of operation.

A portion of our profitability is directly affected by prevailing commodity prices related to our keep-whole processing contracts. In these contracts we are exposed to the spread between NGL product sales price and the purchase price of natural gas. Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. However, in the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, our cost of keeping the producer “whole” would result in operating losses. Due to timing of natural gas purchases and liquid sales, direct exposure to market prices of either natural gas or liquids can be created, because there is an offsetting purchase or sale that remains exposed to market pricing. Certain of our keep-whole processing contracts contain provisions that allow us to charge an incremental fee in the event that processing gas under the contract becomes unprofitable. On occasion, we enter into derivative transactions to manage commodity price risk.

We provide gathering, compression, transportation and processing services to producers and users of natural gas. Our affiliate, QEPM, provides 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 NGL, 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 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 NGL, 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 NGL, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGL not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGL 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 NGL 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 local distribution companies. 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 address seasonal demand and daily supply-demand shifts.

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.

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.

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.

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 NGL or a percentage of the actual residue gas and/or NGL at the tailgate of the processing plant. These types of arrangements expose the gatherer/processor to commodity price risk, as the revenue from the contracts directly correlate with the fluctuating price of natural gas and NGL.

Keep-Whole. Under these arrangements, the service provider keeps 100% of the NGL 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 revenue is based on the price of NGL.

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 gas, 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 move on the system or at a processing facility, as applicable, even in times when total volumes available exceed system capacity.

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.

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.

Natural gas is a significant component of energy consumption in the United States. According to the Energy Information Administration (“EIA”), natural gas consumption accounted for approximately 27% of all energy used in the United States in 2013, representing 26.6 Tcf of natural gas. The EIA estimates that over the next 30 years, total domestic energy consumption will increase by over 11%, 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 2013.

According to the EIA, during the period from 2001 through 2013, natural gas consumption increased by 17% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 71.3 Bcf/d in 2013. 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 53%.

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 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 71.3 Bcf/d in 2013 to 86.7 Bcf/d in 2040.

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 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 coal beds) increasing from 19% of total U.S. natural gas supply in 2008 to 40% in 2012. According to EIA data, during the five-year period from January 2008 through December 2013, marketed domestic production of natural gas increased by an average of approximately 4% 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 2013, the EIA estimated that the United States held 637 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 53% in 2040 as compared with 40% in 2012.

We are currently a wholly owned subsidiary of QEP Resources, Inc., which is a holding company with three major lines of business: crude oil and natural gas exploration and production; midstream field services; and energy marketing. QEP had consolidated revenue for the year ended December 31, 2013 and three months ended March 31, 2014 in excess of $2.9 billion and $884.0 million, respectively, and trades on the NYSE, under the symbol “QEP.” Following the spin-off, we will be an independent, publicly traded company. QEP will not retain any ownership interest in us.

We are a Delaware corporation that owns and operates a diversified portfolio of midstream energy assets. Our business primarily consists of providing natural gas gathering, processing, treating and transportation services and NGL, fractionation and transportation services for our producer customers through our direct ownership and operation of two gathering systems and two processing complexes. In addition, we own a 60% interest in Green River Processing, which owns two processing complexes and one fractionation facility, with the remaining 40% interest owned by QEPM. Our assets, which are strategically located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado and the Uinta Basin located in eastern Utah provide critical infrastructure that links natural gas producers and suppliers to natural gas markets, including various interstate and intrastate pipelines. Finally, we own (i) an approximate 55.8% limited partner interest in QEP Midstream Partners, LP, a publicly traded crude oil and natural gas gathering partnership (NYSE: QEPM), consisting of 3,701,750 common units and 26,705,000 subordinated units and (ii) 100% of QEPM’s general partner, which owns the 2.0% general partner interest in QEPM and 100% of QEPM’s incentive distribution rights. In addition to the 40% interest in Green River Processing, QEPM’s assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which it provides natural gas and crude oil gathering and transportation services.

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, 2014, approximately 84% of our gathering revenue was generated pursuant to contracts with remaining terms in excess of five years, including 59% of our gathering revenue that was generated pursuant to “life-of-reserves” contracts. We provide our processing, treating and fractionation services through fee-based and keep-whole arrangements. For the three months ended March 31, 2014, approximately 43% of our processing, treating and fractionation revenue was generated pursuant to fee-based arrangements. In addition to our fee-based and keep-whole arrangements, for the three months ended March 31, 2014, approximately 3% of our revenue was generated through the sale of condensate volumes that we collect on our gathering systems.

fees on actual volumes processed or from cash payments to cover any minimum volume commitment shortfall. At March 31, 2014, we had an aggregate of approximately 162 Bcf of minimum volume commitments for processing with original terms that range from 10 years to 18 years and, as of March 31, 2014, had a weighted average remaining life of approximately 8 years, assuming minimum volumes for the remainder of the term. At March 31, 2014, we had an aggregate of approximately 161 Bcf of minimum volume commitments and 30 Bcf of capacity reservations on our gathering systems with original terms that range from 5 years to 20 years and, as of March 31, 2014, had a weighted average remaining life of approximately 6 years assuming minimum volumes for the reminder of the term.

Our principal business objective is to increase stockholder value over time by pursuing the following business strategies:

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

The following sections describe our natural gas gathering, processing and fractionation assets as well as our interests in and the assets of QEP Midstream Partners, LP, and the services we provide to our customers.

Overview. The Uinta Basin Gathering System consists of natural gas gathering systems and compression assets located in northeast Utah, which include a combined 610 miles of low-pressure gathering pipeline and 54,306 bhp of natural gas compression.

The following table and map provide information regarding our Uinta Basin Gathering System assets as of March 31, 2014:

Contracts. The Uinta Basin Gathering System is primarily supported by acreage dedications and long-term, fee-based gathering agreements that contain annual inflation adjustment mechanisms and minimum volume commitments. For the three months ended March 31, 2014, approximately 95% of the throughput volumes on the gathering system were gathered pursuant to contracts with remaining terms of more than four years. The

gathering system has average minimum volume commitments of approximately 218 thousand MMBtu/d of natural gas from one producer through 2018. For a discussion regarding our minimum volume commitments, please read “Business—Our Assets and Operations—Minimum Volume Commitments.”

Customers. For the three months ended March 31, 2014, two customers accounted for approximately 95% of the total natural gas throughput and 86% of the total revenue on the Uinta Basin Gathering System. Our largest customer on the gathering system is EOG, which accounted for approximately 104 thousand MMBtu/d, or 59%, of the total natural gas throughput and 45% of the total generated revenue for the three months ended March 31, 2014. The other primary customer on our gathering system is QEP, which accounted for 37% of the total natural gas throughput during the three months ended March 31, 2014.

Delivery Points. Natural gas gathered on the Uinta Basin Gathering System is delivered to our Uinta Basin Complex. We believe our processing facilities are strategically well positioned because they provide producers direct access to four interstate gas pipelines. In addition, producers have access to the Mont Belvieu NGL market via the Mid America Pipeline (“MAPL”) system.

Supply. The Uinta Basin Gathering System gathers natural gas from fields located in the Uinta Basin of northeast Utah. Major natural gas fields gathered by the system include the Redwash, Wonsits Valley, Northern Natural Buttes, Chapita and Glen Bench fields in Uintah County, Utah. QEP owns over 120,000 gross acres in the Uinta Basin that are dedicated to our Uinta Basin Gathering System.

Overview. Uintah Basin Field Services is a joint venture between us, Discovery and Ute Energy that was formed to allow our partners and us to jointly develop natural gas gathering infrastructure within a defined area of mutual interest located in the southeastern Uinta Basin. We operate the gathering system.

The following table and map provide information regarding our Uintah Basin Field Services gathering system as of March 31, 2014:

Contracts. The Uintah Basin Field Services gathering system is supported by long-term, fee-based gas gathering agreements that contain firm throughput commitments, which generate fees whether or not the capacity is used. Approximately 93% of throughput volumes for the three months ended March 31, 2014, were subject to contracts with remaining terms of more than 12 years. The gathering system has aggregate minimum volume commitments of 50 thousand MMBtu/d from three different producers through 2026. The system is currently fully subscribed due to these firm commitments, but we believe we can easily expand this system by adding incremental compression or looping a portion of the existing pipeline. For a discussion regarding our minimum volume commitments, please read “Business—Our Assets and Operations—Minimum Volume Commitments.”

Customers. QEP, Discovery and Ute Energy are the three largest shippers on the Uintah Basin Field Services gathering system, representing approximately five thousand MMBtu/d, three thousand MMBtu/d, and one thousand MMBtu/d, respectively, or 93% in the aggregate, of the throughput on the system for the three months ended March 31, 2014. The remaining throughput on the system was comprised of production from several other third-party producers.

Delivery Points. Natural gas gathered on the Uintah Basin Field Services gathering system is delivered into QEPM’s Three Rivers Gathering system where is it ultimately delivered to either our Uinta Basin Complex or to a third-party processing facility.

Supply. The primary sources of supply for the Uintah Basin Field Services system are the National Oil Shale Reserve, North Hill Creek, and Wolf Flat/Flat Rock fields located along the southern margin of the Uinta Basin in Uintah County, Utah. QEP has over 35,000 gross acres of operated leasehold that are dedicated to our Uintah Basin Field Services gathering system.

Overview. The Blacks Fork Complex, located in Sweetwater and Uinta counties, Wyoming, consists of three separate gas processing trains with total raw gas inlet processing capacity of up to 835 MMcf/d, depending on operating mode, and a NGL fractionation facility with total inlet capacity of approximately 15,000 Bbl/d. The Blacks Fork Complex processed an average of approximately 430 thousand MMBtu/d of natural gas and fractionated an average of 11,917 Bbl/d of NGL during the three months ended March 31, 2014. The complex receives the majority of its gas from the Pinedale Anticline and the Moxa Arch fields located in the Green River Basin of western Wyoming.

The following table and map provides information regarding our Blacks Fork Complex assets as of March 31, 2014:

The original cryogenic train, Blacks Fork I, was commissioned in 1995 and has raw gas inlet capacity of approximately 85 MMcf/d. In 2006, a 250 MMcf/d Joule-Thomson (JT) train was reconfigured at the complex and was combined with an existing 80 MMcf/d JT train, bringing the total JT processing capacity to 330 MMcf/d at the location. The combined train is designed to recover sufficient NGL from the raw gas to meet maximum hydrocarbon dewpoint specifications of connected downstream interstate pipelines. The JT train currently acts as a backup for the other Blacks Fork processing trains during periods of maintenance.

Commissioned in 2011, Blacks Fork II was the third processing train built at the complex. This train was the first grass roots facility built that utilized two of Ortloff Engineers, LTD, licensed processes together, the Recycle Split Vapor (“RSV”) and Carbon Dioxide Control (“CDC”). The train is able to switch between the Gas Subcooled Process (“GSP”) and RSV process modes to maximize NGL recoveries at various volumes and inlet gas compositions depending on customer processing needs.

The RSV process allows for greater ethane recovery than a typical GSP facility and is available for use at raw gas inlet volumes up to 350 MMcf/d, while the GSP process allows this train to operate at the maximum raw gas inlet capacity of 420 MMcf/d but has a slightly lower ethane recovery. The CDC technology allows this train

to operate in either RSV or GSP mode obtaining high ethane recovery without the need for costly CO₂ removal facilities upstream of the cryogenic process.

The Blacks Fork Complex also includes a fractionation facility with a combined capacity of 15,000 Bbl/d of raw NGL. The original fractionator was constructed at the same time as Blacks Fork I and had a capacity of 5,000 Bbl/d. An additional 10,000 Bbl/d of capacity was added in the second quarter of 2013 and incorporates a butane splitter and expanded truck and rail loading facilities. The fractionation facility allows for production of propane, iso and normal butane, and gasoline-range products for delivery and sales to local, regional and national markets.

The following table provides several key metrics associated with the Blacks Fork Complex assets as of March 31, 2014:

Contracts. We are party to the Gas Conditioning Agreement with QEPM whereby QEPM has agreed to make available to us at the Blacks Fork Complex natural gas volumes that it has gathered pursuant to certain “life-of-reserves” and long-term, natural gas gathering agreements with several producer customers. Pursuant to the terms of the Gas Conditioning Agreement, we have been assigned QEPM’s conditioning and keep-whole processing rights detailed in the underlying gathering agreements. For a description of the Gas Conditioning Agreement, please read “Arrangements Between QEP and Our Company and Other Related Party Transactions—Agreements Between QEP and Us—Gas Conditioning Agreement.” Approximately 68% of the inlet volumes for the three months ended March 31, 2014, were processed under a fee-based agreement with a remaining term of more than 12 years. Approximately 30% of the inlet volumes for the three months ended March 31, 2014, at the Blacks Fork Complex were processed under the Gas Conditioning Agreement. The complex has average minimum volume commitments of 230 thousand MMBtu/d from QEP through 2025. For a discussion regarding our minimum volume commitments, please read “Business—Our Assets and Operations—Minimum Volume Commitments.”

Producer Customers. Three producer customers accounted for approximately 98% of the natural gas inlet volumes and approximately 95% of the natural gas processing revenue at the Blacks Fork Complex for the three months ended March 31, 2014. QEP gas production totaled approximately 284 thousand MMBtu/d, or 67%, of the inlet volumes at the complex for the three months ended March 31, 2014, making it our largest producer customer. The remaining inlet volumes for the three months ended March 31, 2014 consisted of production from several third-party producers, including Ultra and Questar, which represented approximately 16% and 14%, respectively.

Delivery Points. The Blacks Fork Complex is uniquely positioned to provide direct access to five interstate gas pipelines: NWPL; KRPL (via Rendezvous Pipeline); the Overthrust Pipeline (“OTPL”); the Colorado Interstate Gas Pipeline (“CIG”); and the Questar Pipeline Company Pipeline (“QPC”). Direct access to REX is provided via OTPL. 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 / 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 KRPL. In addition, the complex has access to two interstate liquids pipelines, MAPL and Overland Pass Pipeline, which provide direct access to the Mont Belvieu and Conway NGL markets. Finally, the complex has access to local, regional and national NGL markets through its rail and truck loading facilities.

Overview. The Emigrant Trail Complex, located in Uinta County, Wyoming, consists of one cryogenic gas processing train with total raw gas inlet capacity of approximately 55 MMcf/d and had average daily throughput of approximately 48 thousand MMBtu/d for the three months ended March 31, 2014. The complex receives the majority of its gas from various gas fields along the Moxa Arch, including Church Buttes, located in the Green River Basin of western Wyoming.

The following table and map provides information regarding our Emigrant Trail Complex as of March 31, 2014:

The original plant was commissioned in 1984 and was acquired by QEPFS in 2005. When inlet capacity allows, the plant also receives gas volumes from the Pinedale Anticline Field via a pipeline connection from the Blacks Fork Complex.

The following table provides several key metrics associated with the Emigrant Trail Complex as of March 31, 2014:

Contracts. The Emigrant Trail Complex is supported by fee-based and keep-whole processing agreements. For the three months ended March 31, 2014, approximately 15% of the inlet volumes were processed pursuant to fee-based agreements with the remaining volumes processed under keep-whole arrangements.

Customers. Questar and Anadarko combined accounted for approximately 99% of the natural gas inlet volumes and 99% of the natural gas processing revenue at the Emigrant Trail Complex for the three months ended March 31, 2014. The remaining inlet volumes consisted of production from another third-party producer.

Delivery Points. The Emigrant Trail Complex provides direct access to the natural gas market via QPC. In addition, the plant has access to MAPL, which provides access to the Mont Belvieu NGL market.

Overview. The Vermillion Complex, located in Sweetwater County, Wyoming, consists of one cryogenic processing train with total raw gas inlet capacity of approximately 43 MMcf/d and had average daily throughput of 45 thousand MMBtu/d for the three months ended March 31, 2014. The complex receives the majority of its gas from the Canyon Creek, Trail and Hiawatha fields in the Vermillion sub-basin in southern Wyoming and northwest Colorado.

The following table and map provides information regarding our Vermillion Complex as of March 31, 2014:

The original plant was commissioned in 1998 as a joint venture between QEPFS and Wexpro Company, a Questar subsidiary. An expansion project is currently in progress that will increase total inlet capacity to approximately 57 MMcf/d by the third quarter of 2014.

The following table provides several key metrics associated with the Vermillion Complex as of March 31, 2014:

Contracts. We are party to the Gas Conditioning Agreement with QEPM whereby QEPM has agreed to make available to us at the Vermillion Complex natural gas volumes that it has gathered pursuant certain natural gas gathering agreements with several producer customers. Pursuant to the terms of the Gas Conditioning Agreement, we have been assigned QEPM’s conditioning and processing rights detailed in the underlying gathering agreements. For a description of the Gas Conditioning Agreement, please read “Arrangements Between QEP and Our Company and Other Related Party Transactions—Arrangements Between QEP and Us—Gas Conditioning Agreement.” Approximately 74% of the inlet volumes for the three months ended March 31, 2014 were processed under fee-based agreements. Approximately 26% of the inlet volumes for the three months ended March 31, 2014 at the Vermillion Complex were processed under the Gas Conditioning Agreement.

Producer Customers. Questar is the largest producer customer of the Vermillion Complex representing approximately 26% of the natural gas inlet volumes and 69% of the natural gas processing revenue for the three months ended March 31, 2014. The remaining inlet volumes consisted of production from several other producers, including Devon, QEP and Chevron.

Delivery Points. The Vermillion Complex provides direct access to the natural gas market via QPC. In addition, the plant has access to MAPL, which provides access to the Mont Belvieu NGL market.

Overview. The Uinta Basin Complex, located in Uintah County, Utah, consists of four separate processing trains with total raw gas inlet processing capacity of up to 650 MMcf/d. The complex had average daily throughput of approximately 276 thousand MMBtu/d for the three months ended March 31, 2014. The complex receives the majority of its gas from various natural gas fields located in the Uinta Basin.

The following table and map provides information regarding our Uinta Basin Complex assets as of March 31, 2014:

Our first gas processing plant in the Uinta Basin Complex, Redwash/24B, was acquired in 2002 from Shenandoah Energy. The refrigeration plant is located in the Red Wash Field and had raw gas inlet capacity of approximately 70 MMcf/d. In 2005, we expanded the capacity of the Redwash/24B plant by adding another 70 MMcf/d refrigeration train bringing total inlet processing capacity to 140 MMcf/d. The combined train was designed to recover sufficient liquid hydrocarbons from the gas to meet maximum hydrocarbon dewpoint specifications of connected downstream interstate pipelines.

Commissioned in 2008, the Stagecoach refrigeration plant, located approximately 20 miles south of the Red Wash/24B plant, was the next processing train built as part of the Uinta Basin Complex and had processing capacity of 200 MMcf/d. The plant was originally constructed to provide us access to gathered natural gas volumes from a wider geographic area, including volumes gathered on the Three Rivers Gathering and Uinta Basin Field Services gathering systems.

In 2011, in response to increasing third-party producer demand in the region, we added our initial cryogenic processing capacity to the Uinta Basin Complex through the construction of the Iron Horse I processing plant. The 155 MMcf/d Iron Horse I cryogenic processing train, located next to the Stagecoach processing plant, allowed us to maximize NGL recoveries at the location. In 2013, we added a second 155 MMcf/d cryogenic processing train, Iron Horse II, bringing total raw gas, cryogenic processing capacity to 310 MMcf/d at the location. Currently, the Stagecoach refrigeration plant primarily acts as a backup for the Iron Horse processing trains during periods of maintenance.

The following table provides several key metrics associated with the Uinta Basin Complex assets as of March 31, 2014:

Contracts. The Uinta Basin Complex is supported by long-term, fee-based processing agreements with minimum volume commitments. Approximately 72% of inlet volumes for the three months ended March 31, 2014, at the complex were processed pursuant to contracts with remaining terms of more than six years. The complex has aggregate minimum volume commitments averaging 415 thousand MMBtu/d from three producers through 2019. For a discussion regarding our minimum volume commitments, please read “Business—Our Assets and Operations—Minimum Volume Commitments.”

Customers. Four customers accounted for approximately 96% of the natural gas inlet volumes and approximately 95% of the natural gas processing revenue at the Uinta Basin Complex for the three months ended March 31, 2014. EOG’s gas production totaled approximately 99 thousand MMBtu/d, or 36%, of the inlet volumes at the complex for the three months ended March 31, 2014, making it our largest customer. The remaining inlet volumes for the three months ended March 31, 2014 consisted of production from several third-party producers, including QEP, EnerVest and XTO, which represented approximately 24%, 23%, and 13%, respectively.

Delivery Points. The Uinta Basin Complex is strategically positioned to provide direct access to four interstate gas pipelines: QPC; NWPL; the Wyoming Interstate Pipeline (“WIC”); and CIG. We believe these pipeline interconnects maximize producers’ marketing alternatives by providing access to natural gas markets in the Pacific Northwest via NWPL, regional markets along the eastern Rocky Mountains via CIG and WIC and the Wasatch Front in Utah via QPC. In addition, the complex has access to MAPL, which provides direct access to the Mont Belvieu NGL markets. Finally, the complex has access to local and regional NGL markets through its truck loading facilities.

We own (i) an approximate 55.8% limited partner interest in QEP Midstream Partners, LP, a publicly traded crude oil and natural gas gathering partnership (NYSE: QEPM), consisting of 3,701,750 common units and 26,705,000 subordinated units and (ii) 100% of QEPM’s general partner, which owns the 2.0% general partner interest in QEPM and 100% of QEPM’s incentive distribution rights. QEPM is a limited partnership formed in April 2013 to own, operate, acquire and develop midstream energy assets. QEPM’s primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which it provides natural gas and crude oil gathering and transportation services. In addition, upon the closing of the transactions contemplated by the Purchase and Sale Agreement, which is expected to occur on July 1, 2014, QEPM will own a 40% interest in Green River Processing, which owns the Blacks Fork and Emigrant Trail processing complexes. QEPM’s assets are located in, or are within close proximity to, the Green River Basin, the Uinta

Basin located in eastern Utah, and the Williston Basin located in North Dakota. The following table provides information regarding QEPM’s assets by system as of March 31, 2014:

Our Green River system, located in western Wyoming, consists of three integrated assets—the Green River gathering assets (“Green River Gathering Assets”), the assets owned by Rendezvous Gas Services, L.L.C. (“Rendezvous Gas”) and the assets owned by 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 and production activities in the Pinedale Field.

The Green River Gathering Assets are primarily supported by “life-of-reserves” and long-term, fee-based gathering agreements. The primary customers of these assets include QEP, QGC, and WGR Operating, LP.

Rendezvous Gas is a joint venture between QEPM and Western Gas Partners, LP (“Western Gas”), which 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 QEPM or Western Gas. Rendezvous Gas entered into separate agreements with QEPM and Western Gas to gather the natural gas dedicated to each party from producers within an area of mutual interest.

Rendezvous Pipeline provides gas transportation services from our Blacks Fork Complex in southwest Wyoming to an interconnect with the Kern River Pipeline. The capacity on the Rendezvous Pipeline system is contracted under long-term take or pay transportation contracts with remaining terms of more than nine years.

The Vermillion gathering system (“Vermillion Gathering System”) consists of gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah. 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 QEPM 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 the Vermillion Gathering System include QGC, Wexpro, QEP and Chevron. For the three months ending March 31, 2014, 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.

Three Rivers Gathering, L.L.C. (“Three Rivers Gathering”) is a joint venture between QEPM and Ute Energy, which was formed to transport natural gas gathered by Uintah Basin Field Services, an indirectly owned subsidiary in which we own a 38% interest, and other third-party volumes to gas processing facilities owned by QEP and third parties. Three Rivers Gathering is primarily supported by long-term, fee-based gas gathering agreements with minimum volume commitments. As of March 31, 2014, the system has aggregate minimum volume commitments of 210 thousand MMBtu/d from three different producers through 2017. The primary customers on QEPM’s Three Rivers Gathering system include EnerVest, XTO, Anadarko and QEP.

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 is primarily supported by long-term, fee-based, crude oil and gas gathering agreements with minimum volume commitments. As of March 31, 2014, 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 2025. QEP and Marathon Oil Company are currently the only customers on the Williston Gathering System.

Several of our gathering and processing agreements contain minimum volume commitments, pursuant to which our customers guarantee to ship a minimum volume of natural gas or crude oil on our gathering systems or to process a minimum volume of natural gas at our processing complexes. The original terms of the minimum volume commitments range from 5 to 20 years. In addition, certain of our customers have an aggregate minimum volume commitments, which is a total amount of natural gas or crude oil that the customer must transport on our gathering systems or process at our processing complexes 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 or processing rate multiplied by the actual throughput volumes shipped or volumes processed.

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 or processed for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering or processing 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 and processing 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:

The midstream crude oil and natural gas industry is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for natural gas and crude oil 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 Company, Inc.

In addition to competing for natural gas and crude oil 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 and processing agreements, we believe that our gathering systems and other midstream assets will not face significant competition from other pipelines or facilities for QEP’s natural gas, crude oil or NGL transportation requirements.

Our operations, most notably in the Pinedale Field, are affected by seasonal weather conditions. For example, 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, QEPM will not add throughput on its Green River system, which supplies our Blacks Fork Processing Complex, during this period, and existing levels of throughput may decline as the wells connected to the 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.

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 maintain corporate property, liability, business interruption and pollution liability insurance policies at varying levels of deductibles and limits that we believe are 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.

Some of our natural gas pipelines are subject to regulation by the PHMSA pursuant to the NGPA, as amended by the PSA, the APSA, the PSIA, the PIPES Act, and the 2011 Pipeline Safety Act. The NGPA 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”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. QEPM’s crude oil pipeline and certain of its 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, which 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. 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:

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 non-exempt pipelines, particularly QEPM’s Rendezvous Pipeline assets and Green River and Williston gathering systems. We currently estimate that we will incur approximately $300,000 in costs during 2014 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.

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. Effective October 25, 2013, PHMSA adopted new rules increasing 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 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 and maximum operating pressure. We have performed hydrotests on the majority of our facilities to confirm the maximum allowable operating pressure and maximum operating pressure and do not expect that any final rulemaking by PHMSA regarding such records verification 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 (“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, 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.

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

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of the facilities we consider to be gathering facilities, 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. 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 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, it could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rates established by the FERC.

States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based regulation. Our natural gas and crude oil 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, and 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.

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (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 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 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 CFTC is directed under the Commodities Exchange Act (“CEA”) to prevent price manipulations in the commodity, futures, and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures, and swaps markets. The CFTC 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 provisions of the CEA.

The EPAct 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.

On November 15, 2012, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether to amend its regulations under the natural gas market transparency provisions of Section 23 of the NGA, as adopted by EPAct 2005, to consider the extent to which quarterly reporting of every natural gas transaction within the FERC’s NGA jurisdiction that entails physical delivery for the next day or next month would provide useful information for improving natural gas market transparency. On July 9, 2013, the FERC provided notice that it was making a data request of certain natural gas marketers to better assess the reporting requirements. The FERC has not yet issued an order.

QEPM owns 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 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 QEPM’s 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.

QEPM’s 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 NGL, 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, QEPM files 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 QEPM’s rate levels were investigated, the inquiry could result in a comparison of its 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.

Our operation of pipelines and other facilities for the gathering of natural gas and other products is subject to stringent and complex federal, state, local and tribal 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:

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, local or tribal 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 and process 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.

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 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. Despite CERCLA’s “petroleum exclusion,” 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 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 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.

Our operations are subject to the CAA, and comparable state, local and tribal 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 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, utilize specific emission control technologies to limit emissions, and/or retrofit existing emission sources with new controls. 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 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 and/or complying with new federal and/or state source-specific emission standards. 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.

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.

The 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, our operations and financial condition have not been materially impacted. 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.

The National Environmental Policy Act (“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 that may result in longer review processes that could lead to delays and increased costs that could materially adversely affect our revenue and results of operations.

Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. For example, the EPA has established a preconstruction permitting program for new and modified minor sources throughout Indian Country, and new and modified major sources in nonattainment areas in Indian Country. 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. One or more of these laws and regulations 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 gathering operations on such lands.

In December 2009, the EPA determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, regulates emissions of GHGs

from certain large stationary sources of emissions such as power plants or industrial facilities, and requires the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas production and onshore processing, transmission, storage and distribution facilities. In addition, the EPA has continued to adopt GHG regulations for other industries. 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.

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. 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.

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.

We do not conduct hydraulic fracturing operations, but 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. The process is typically regulated by state oil and natural-gas commissions, but the EPA and other federal agencies have asserted federal regulatory authority over the process. For example, the EPA has announced its intent to propose standards for wastewater discharge from oil and gas extraction activities, and in May 2014 issued an Advanced Notice of Proposed Rulemaking seeking public comment on its plans to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In addition, the DOI published a revised proposed rule on May 24, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity, and handling of flowback water.

Scrutiny of hydraulic fracturing activities continues in other ways. For example, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing activities, the EPA has commenced a study of the potential impacts of hydraulic fracturing on drinking water and groundwater, and the U.S. Department of Energy evaluated practices it could recommend to ensure the safety of hydraulic fracturing activities.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing

process. At the state level, some states have adopted, and other states are considering adopting, laws and/or regulations that could impose more stringent permitting, disclosure and well construction requirements on natural gas drilling activities. Local governments 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 or regulations 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.

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security (the “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 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 the 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. We believe that none of our facilities are material 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.

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. While we have implemented our own cyber-security programs and protocols that meet or exceed the proposed standards, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

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 addition, portions of the land on which our processing, treating and fractionation facilities and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. Other portions of land on which our processing, treating and fractionation facilities and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership in such lands. We have no knowledge of any challenge to the underlying fee title of any

material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

We believe that we have obtained or will obtain sufficient third-party consents, permits, and authorizations for us to operate our business in all material respects as described in this information statement. With respect to any consents, permits, or authorizations that have not been obtained, we believe that these consents, permits, or authorizations will be obtained after the closing of the spin-off, or that the failure to obtain these consents, permits, or authorizations will not have a material adverse effect on the operation of our business.

We believe that we will have satisfactory title to all of our assets at the closing of the spin-off. Record title to some of our assets may continue to be held by 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 the completion of the spin-off. We will make these filings and obtain these consents upon completion of the spin-off. 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 us or QEP, we believe 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.

At March 31, 2014, we had approximately 250 full-time employees dedicated to our business. This number does not include employees of QEP who provide services to our business and other of QEP’s businesses.

We are the subject of ongoing litigation with QGC, Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. Our former affiliate QGC filed its complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, an accounting and declaratory judgment related to a 1993 gathering agreement (“1993 Agreement”) executed when we and QGC were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of our systems provided gathering services to QCG and we charged an annual gathering rate that is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of QEPM’s IPO, the assets and the 1993 Agreement were assigned by us to QEPM. QGC netted the disputed amount from its monthly payments of the gathering fees to us and has continued to net such amounts from its monthly payments to QEPM. As of March 31, 2014, QEPM has deferred revenue of $9.9 million related to the QGC disputed amount. We have filed counterclaims seeking damages and declaratory judgment relating to our gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEPM as a defendant in the litigation. QEPM has been indemnified by QEP for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the omnibus agreement entered into between us, QEPM and QEP in connection with QEPM’s IPO. Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

to a 2010 gas processing agreement (the “XTO Agreement”). We process XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires us to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing our allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. XTO is seeking damages, but specific monetary damages have not been asserted.

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.

We are in the process of identifying the individuals who will be appointed to serve as our executive officers following the date of distribution, and will provide information regarding these individuals in an amendment to this information statement.

We are in the process of identifying the individuals who will be appointed to serve as our directors following the date of distribution, and will provide information regarding these individuals in an amendment to this information statement.

As of the date of the distribution, we expect that our Board will consist of members, of whom will meet applicable regulatory and exchange listing independence requirements. Upon completion of the spin-off, our directors will be divided into three classes serving staggered three-year terms. Class I directors will have an initial term expiring in 2015, Class II directors will have an initial term expiring in 2016 and Class III directors will have an initial term expiring in 2017.

At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our Board could have the effect of increasing the length of time necessary to change the composition of a majority of the Board. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the Board.

The committees of our Board will include an Audit Committee, a Nominating and Governance Committee and a Compensation Committee, each as further described below. Following our listing on the NYSE and in accordance with the transition provisions of the rules of the NYSE applicable to companies listing in conjunction with a spin-off transaction, each of these committees will, by the date required by the rules of the NYSE, be composed exclusively of directors who are independent. Other committees may also be established by the Board from time to time.

Prior to completion of the spin-off, our Board will establish an audit committee, composed of at least three directors. The Board is expected to determine that all of the audit committee members are financially literate and that at least one member is an “audit committee financial expert” for purposes of the SEC rules.

The audit committee’s functions will include providing assistance to the Board in fulfilling its oversight responsibility relating to our financial statements and the financial reporting process, compliance with legal and regulatory requirements, the qualifications and independence of our independent registered public accounting firm, our system of internal controls, the internal audit function, our code of ethical conduct, retaining and, if appropriate, terminating the independent registered public accounting firm, and approving audit and non-audit services to be performed by the independent registered public accounting firm. The responsibilities of the audit committee, which are anticipated to be substantially identical to the responsibilities of QEP’s audit committee, will be more fully described in the audit committee charter that will be adopted by our Board. The audit committee charter will be posted on our corporate website on or prior to the distribution date.

In compliance with the NYSE listing standards, our audit committee will annually conduct a self-evaluation to determine whether it is functioning effectively. In addition, the audit committee will prepare the report of the committee required by the rules and regulations of the SEC to be included in our annual proxy statement.

Prior to completion of the spin-off, our Board will establish a nominating and governance committee, composed of at least one director.

The nominating and governance committee’s functions will include identifying individuals qualified to become members of the Board consistent with criteria approved by the Board, recommending to the Board candidates for election at the annual meeting of stockholders, developing, reviewing and recommending to the Board a set of corporate governance guidelines and overseeing the evaluation of the Board and management. The responsibilities of the nominating and governance committee, which are anticipated to be substantially identical to the responsibilities of QEP’s nominating and governance committee, will be more fully described in the nominating and governance committee charter that will be adopted by our Board. The nominating and governance committee charter will be posted on our corporate website on or prior to the distribution date.

In compliance with the NYSE listing standards, our nominating and governance committee will annually conduct a self-evaluation to determine whether it is functioning effectively.

Prior to completion of the spin-off, our Board will establish a compensation committee, composed of at least one director.

The compensation committee’s functions will include reviewing and approving corporate goals and objectives relevant to the compensation of executive officers, evaluating the performance of executive officers in light of those goals and objectives, determining and approving the compensation level of the executive officers based on their evaluations, and making recommendations to the Board with respect to incentive-compensation and equity-based plans that are subject to the approval of the Board. The responsibilities of the compensation committee, which are anticipated to be substantially identical to the responsibilities of QEP’s compensation committee, will be more fully described in the compensation committee charter that will be adopted by our Board. The compensation committee charter will be posted on our corporate website on or prior to the distribution date.

In compliance with the NYSE listing standards, our compensation committee will annually conduct a self-evaluation to determine whether it is functioning effectively. In addition, the compensation committee will prepare the report of the committee required by the rules and regulations of the SEC to be included in our annual proxy statement.

Our Board is expected to formally determine the independence of its directors following the spin-off. In addition, our Board is expected to annually determine the independence of directors based on a review by the directors and the nominating and governance committee. In affirmatively determining whether a director is independent, the Board will determine whether each director meets the objective standards for independence set forth in the NYSE rules.

During the three months ended March 31, 2014, our business was operated by QEP and its subsidiaries and not through an independent company. Therefore we did not have a compensation committee or any other committee serving a similar function. Decisions as to the compensation of those individuals who will serve as our executive officers were made by QEP. See “Executive Compensation.”

In connection with the spin-off, our Board will adopt a code of ethics that applies to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions. Our code of ethics will be publicly available on our corporate website. Any waiver of our code of ethics with respect to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions may only be authorized by our audit committee and will be disclosed as required by applicable law.

As an “emerging growth company” under SEC rules, we are not required to include a Compensation Discussion and Analysis section and have elected to comply with the scaled disclosure requirements applicable to emerging growth companies. This executive compensation disclosure provides an overview of the 2013 executive compensation program for our named executive officers (“NEOs”) identified below. For 2013, our NEOs were:

While this group of executive officers reflects our executive leadership team as of December 31, 2013, the selection of our future executive officers is ongoing and certain of these executives, specifically, Messrs. Stanley and Doleshek will not continue as executive officers of Entrada following our separation from QEP. In addition, the compensation amounts and discussion set forth herein reflect compensation programs and decisions of and implemented by the compensation committee of QEP’s board of directors. Following our separation from QEP, compensation decisions will be made by our compensation committee pursuant to compensation programs and philosophies that our compensation committee will establish, which may not be the same as or similar to QEP’s programs.

The following summarizes the total compensation awarded to, earned by or paid to our NEOs for fiscal years 2012 and 2013, which amounts were paid for such years by QEP. The amounts shown represent the NEOs’ total compensation by QEP for the relevant years; however, Messrs. Stanley and Doleshek devoted less than a majority of their time to the management of our business for these years.

For additional information about the stock awards granted to the NEOs for 2013, see the discussion below under the heading “—Long-Term Incentives.”

This table shows outstanding equity awards for the NEOs under QEP’s equity incentive plans. All values shown are as of December 31, 2013.

For fiscal year 2013, QEP’s compensation program was composed of elements designed to address a variety of objectives and compensation decisions were generally made by the compensation committee of QEP’s board of directors. The table below highlights each element of QEP’s compensation program for 2013 and the primary role of such element in achieving QEP’s compensation objectives.

With the assistance of its independent compensation consultant, Meridian Compensation Partners, QEP’s compensation committee reviews each NEO’s target total compensation each year, makes adjustments to base salary and annual incentive target where warranted, and determines the long-term incentive grant for each NEO.

Charles Stanley—QEP’s President and Chief Executive Officer. Mr. Stanley provides executive leadership to QEP and its Board of Directors. His responsibilities include providing strategic direction to position the Company for long-term shareholder value creation, organizational leadership and overall accountability for financial and operating performance. Effective management of communications with shareholders, potential investors, and the Board are also critical components of his role.

The following table outlines Mr. Stanley’s total compensation target change from 2012 to 2013:

Richard Doleshek—QEP’s Executive Vice President and Chief Financial Officer. Mr. Doleshek provides executive leadership to several key corporate functions, including finance, treasury, accounting, risk, tax, investor relations, information technology and internal audit.

The following table outlines Mr. Doleshek’s total compensation target change from 2012 to 2013:

Perry Richards—Senior Vice President, QEP Field Services. Mr. Richards provides executive leadership to QEP Field Services, ensuring we are maximizing shareholder value over the long term in our midstream business. Mr. Richards’ role includes all components of running a successful midstream business, including accountability for commercial decisions, oversight of contract and agreement structure, operation of plants and gathering systems, as well as the health, safety and environmental function within Field Services.

The following table outlines Mr. Richards’ total compensation target change from 2012 to 2013:

QEP’s annual incentive program is based on key one-year financial and operational metrics and achievement of strategic goals that drive long-term shareholder value. This qualitative assessment of the achievement of strategic objectives allows QEP’s compensation committee to encourage management’s efforts in areas that position QEP for future success, but are less quantifiable, and to adjust for the results achieved.

The following diagram summarizes the calculation of company performance for QEP’s annual incentive program:

The following chart shows the designated goals for each metric. Payout on each of the quantitative metrics ranges from 0% to 200%, with results interpolated between the 50% of target and 200% of target goals. Achievement of strategic objectives is determined at the discretion of QEP’s compensation committee and can range from 0% to 200%.

For 2013, QEP achieved the adjusted EBITDA, oil production and total production goals at near target levels and determined that strategic objectives were achieved at levels warranting a total Company score of 100% of target for the NEOs’ annual incentive payouts.

Once the QEP Company score is determined, QEP’s Compensation Committee then may apply an individual performance multiplier to each NEO’s award amount on a discretionary basis, based upon an assessment of progress on important Company initiatives and overall performance of the areas within each NEO’s accountability. For 2013, no individual performance adjustments were made. As a result all of the NEOs received annual incentive awards at 100% of the target level.

The long-term incentive program is designed to align executive compensation with a focus on QEP’s long-term stock price and TSR performance, both on an absolute basis and relative to industry peers. For NEOs, QEP’s compensation committee determines the total long-term incentive value, which for 2013 was divided equally between three vehicles described in the following tables. For 2014, the QEP Compensation Committee approved a change to the weighting of the three vehicles for NEOs to align with current market practices and increase the portion of LTI tied to TSR performance. The 2014 weighting is 40% PSUs, 20% stock options and 40% restricted stock.

PSUs are phantom shares of stock that track the value of QEP shares but are settled in cash. PSUs align QEP’s executive compensation with QEP’s TSR relative to its peers in its industry. The value realized for PSUs is dependent on both stock price and QEP’s relative TSR performance over a three-year period. The chart below summarizes the features of the PSU grants to the NEOs.

Stock options align QEP’s executive compensation directly with the company’s market value (or stock price) as the stock price must increase for any value to be realized. The chart below summarizes the features of the stock options granted to the NEOs.

Restricted stock aligns our executive compensation directly with the company’s market value (or stock price), encourages retention, and increases employee ownership in the company. The chart below summarizes the features of the restricted stock granted to the NEOs.

To reward certain executives for their work in completing the QEPM IPO and to align the interests of these executives with the interests of QEPM unit holders, QEP’s Compensation Committee recommended, and the board of directors of the General Partner of QEPM approved, an award of QEPM phantom units that were granted under QEPM’s long-term incentive plan at the time of the QEPM IPO. The terms and conditions are similar to QEP restricted stock and upon vesting of the phantom units, the recipients would receive one QEPM common unit or an equivalent amount of cash. The chart below summarizes the features of the QEPM phantom unit grants.

QEP maintains the QEP Resources, Inc. Retirement Plan (Retirement Plan) which is a defined benefit pension plan closed to new participants as well as the QEP Resources, Inc. Supplemental Executive Retirement Plan (SERP), which generally provides highly compensated employees with supplemental retirement benefits to compensate for the limitations imposed by federal tax laws on benefits payable from the tax-qualified defined benefit pension plan. These plans provide retirement benefits to the NEOs generally based upon a formula taking into account the participant’s compensation level and years of service with QEP and its predecessors. In connection with our separation from QEP, it is anticipated that the NEOs who continue with us as executives following the separation will cease to accrue benefits in these plans and QEP will retain all outstanding obligations to the NEOs under these plans. Retirement benefits to be provided to the NEOs in relation to future service following our separation from QEP will be determined by our Compensation Committee.

QEP also offers its employees, including the NEOs, the opportunity to contribute a portion of their compensation up to the annual IRS limit to the QEP Resources, Inc. Employee Investment Plan which is a 401(k) Plan. QEP provides matching contributions on 100% of an employee’s contributions up to 6% of eligible compensation. The employee deferrals and employer contributions are invested, as directed by the participant, in mutual funds or other alternatives, including QEP common stock. QEP also allows its officers, along with certain

other key employees, to defer the receipt of compensation under a Deferred Compensation Wrap Plan. Participants select their investments from a variety of investment options, including QEP phantom shares and an array of mutual funds. Gains and losses on the deferred amounts are tracked against participant-selected investments. The Deferred Compensation Wrap Plan includes both a Deferred Compensation Program and a 401(k) Supplemental Program. Under the deferred compensation program, officers and certain key employees are allowed to defer taxable income and provide for future financial needs. Eligible employees may defer a portion of their base salaries and cash incentives for a maximum of ten years after termination of employment. Amounts deferred under this program are matched by QEP at the same rate as in the 401(k) plan. Under the 401(k) Supplemental Program, NEOs and certain key employees whose compensation exceeds the IRS Limit to defer up to 6% of their salaries in excess of the IRS Limit and receive a Company matching contribution on this deferred amount as if that amount had been contributed to the 401(k) Plan.

According to the provisions in the QEP Executive Severance Plan, participants receive certain severance benefits upon termination following a change in control if such termination is initiated by the employer within three years following the change in control for any reason other than for cause, death or disability, or by the participant for good reason. The severance benefits include the following:

In early 2014, the Compensation Committee approved the QEP Resources, Inc. Basic Executive Severance Compensation Plan (the Basic Severance Plan) which will provide benefits to participating executives upon a qualifying termination of employment. The plan expires on December 31, 2015. All of the NEOs except Mr. Stanley are participants in this new plan. The Compensation Committee believes that the Basic Severance Plan will enhance the Company’s ability to attract and retain executives whose leadership is critical to the Company’s business, by providing a participating executive with income protection in the event that the executive experiences a qualifying termination of employment during the term of the Basic Severance Plan.

Under the Basic Severance Plan, participants are entitled to receive certain severance benefits upon termination of employment by the Company other than for “cause” or due to the participant’s “disability”, or by the participant for “good reason” (each as defined in the Basic Severance Plan), subject to the participant’s execution and non-revocation of a release of claims in favor of the Company. The separation/distribution will not trigger any entitlement to benefits under the Basic Severance Plan. The severance benefits include:

Prior to the completion of the Spin-Off, we expect that our board of directors will adopt and that QEP, as our sole stockholder, will approve an equity compensation plan, the terms and conditions of which are currently being developed. We will update this information statement prior to the Spin-Off once the terms our equity compensation plans have been determined.

Prior to the consummation of this offering, we have not previously paid or incurred any compensation to our directors for their service on our board. Following the consummation of this offering, our officers and employees who also serve as our directors will not receive additional compensation for their service as a member of our board of directors. Directors of our company who are not our officers or employees of our company or of QEP will receive compensation as set by our company’s board of directors from time to time. Upon joining our board, each non-employee director is expected to receive an initial equity incentive award granted under our equity incentive plan having a value of $ . In addition, the annual compensation package for our non-employee directors is initially expected to have an aggregate value of $ , of which % will be paid in cash on a quarterly basis and 50% will be paid in the form of an annual equity incentive award granted under our equity incentive plan. The chair of each standing committee of our company’s board will also receive an additional $ annual cash retainer. 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.

As of the date of this information statement, all outstanding shares of our common stock are owned beneficially and of record by QEP. After the spin-off, QEP will not own any of our common stock. The following table sets forth information with respect to the anticipated beneficial ownership of our common stock by:

Except as otherwise noted below, we based the share amounts shown on each person’s beneficial ownership of QEP common stock on , 2014, and a distribution ratio of shares of our common stock for every shares of QEP common stock held by such person.

To the extent persons who are directors or executive officers or who are expected to serve as directors or executive officers upon completion of the spin-off own QEP common stock at the record date of the spin-off, they will participate in the distribution on the same terms as other holders of QEP common stock.

Immediately following the spin-off, we estimate that shares of our common stock will be issued and outstanding, based on the number of shares of QEP common stock expected to be outstanding as of the record date (excluding treasury shares). The actual number of shares of our common stock outstanding following the spin-off will be determined on , 2014, the record date.

Beneficial ownership has been determined in accordance with the rules of the SEC and includes the power to vote or direct the voting of securities, or to dispose or direct the disposition thereof, or the right to acquire such powers within 60 days. Except as otherwise indicated, the persons or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them. Unless otherwise indicated, the address for each director and executive officer listed is: c/o Entrada Midstream, Inc., .

ARRANGEMENTS BETWEEN QEP AND OUR COMPANY AND OTHER RELATED PARTY TRANSACTIONS

The separation will be accomplished by means of the distribution by QEP of 100% of the outstanding shares of Entrada common stock to holders of QEP common stock entitled to such distribution, as described under “The Spin-Off.” Completion of the distribution will be subject to satisfaction, or waiver by QEP, of the conditions to the spin-off described under “The Spin-Off—Conditions to the Spin-Off.”

As part of the separation and the distribution, we will enter into a Separation and Distribution Agreement and several other agreements with QEP to effect the separation and to provide a framework for our relationship with QEP after the separation. These agreements will provide for the allocation between us and QEP of the assets, liabilities and obligations of QEP and its subsidiaries, and will govern various aspects of the relationship between us and QEP subsequent to the separation, including with respect to transition services, employee benefits, intellectual property rights, tax matters, real estate and other commercial relationships. In addition to the Separation and Distribution Agreement, which contains key provisions related to the spin-off, these agreements will include, among others:

The forms of the agreements described below will be filed as exhibits in an amendment to our registration statement on Form 10 of which this information statement is a part. These summaries do not purport to be complete and are qualified in their entirety by reference to the full text of the applicable agreements, which will be incorporated by reference into this information statement.

The terms of the agreements described below that will be in effect following the separation have not yet been finalized. Changes, some of which may be material, may be made prior to our separation from QEP. No changes may be made after the separation without our consent.

The Separation and Distribution Agreement will govern the terms of the separation of the midstream business from QEP’s other businesses. Generally, the Separation and Distribution Agreement will include QEP’s and our agreements relating to the restructuring steps to be taken to complete the separation, including the assets, equity interests and rights to be transferred, liabilities to be assumed, contracts to be assigned and related matters. Subject to the receipt of required governmental and other consents and approvals, in order to accomplish the separation, the Separation and Distribution Agreement will provide for QEP and us to transfer specified assets and liabilities between the companies that will operate the midstream business after the spin-off, on the one hand, and QEP’s remaining businesses, on the other hand.

Except as expressly set forth in the Separation and Distribution Agreement or any ancillary agreement, it is expected that QEP will not make any representation or warranty as to the assets, equity interests, business or liabilities transferred to or assumed by us as part of the separation, as to any approvals or notifications required in connection with the transfers, as to the value or freedom from any security interests of any of the assets transferred, as to the absence or presence of any defenses or right of setoff or freedom from counterclaim with respect to any claim or other asset of either QEP or us or as to the legal sufficiency of any assignment, document or instrument delivered to convey title to any asset or thing of value transferred in connection with the separation. All assets are expected to be transferred on an “as is,” “where is” basis.

The Separation and Distribution Agreement will specify those conditions that must be satisfied or waived by QEP prior to the spin-off. See “The Spin-Off—Conditions to the Spin-Off” included elsewhere in this information statement. In addition, we expect that QEP will have the right to determine the date and terms of the distribution, and will have the right to determine to abandon or modify the distribution and to terminate the Separation and Distribution Agreement at any time prior to the distribution.

The Separation and Distribution Agreement is also expected to address our and QEP’s obligations with respect to indemnification for various matters, insurance coverage, litigation responsibility, confidentiality obligations, rights to use certain intellectual property and post-spin-off access to information.

The Employee Matters Agreement will govern QEP’s and our compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of each company, and generally will allocate liabilities and responsibilities relating to employee compensation and benefit plans and programs. The Employee Matters Agreement will provide for the treatment of outstanding QEP equity awards and certain other outstanding annual and long-term incentive awards granted previously to QEP employees who will become our employees following the spin-off. The Employee Matters Agreement will provide that, following the spin-off, our active employees generally will no longer participate in benefit plans sponsored or maintained by QEP and will commence participation in our benefit plans. The Employee Matters Agreement also will set forth the general principles relating to employee matters, including with respect to the assignment of employees, the assumption and retention of employment-related liabilities and related assets, expense reimbursements, workers’ compensation, leaves of absence, employee service credit and the sharing of employee information.

The Transition Services Agreement will set forth the terms on which QEP will provide to us, and, if necessary, we will provide to QEP, on a temporary basis, certain corporate services or functions that the companies historically have shared. We expect the agreement will provide for the provision of specified transition services, generally for a period of up to one year, with a possible extension in certain circumstances for limited periods of time. We expect that these services will be provided at cost, as determined by QEP in a manner consistent with cost accounting practices.

We are party to approximately 20 natural gas gathering agreements 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 2 to 12 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 basis. The gathering fee varies by agreement, and the majority of our agreements include annual inflation adjustment mechanisms.

These gathering agreements accounted for approximately 51% of our gathering throughput for the three months ended March 31, 2014. For the three months ended March 31, 2014, QEP accounted for approximately 50% of our gathering revenue.

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 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.

Some of our gathering and processing agreements with QEP contain minimum volume commitments pursuant to which QEP guarantees to ship a minimum volume of natural gas on our gathering systems or processing systems. The original terms of the minimum volume commitments range from 10 to 20 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 or processing 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.

We are party to approximately 10 natural gas processing agreements with QEP. Our processing agreements are long-term contracts with fee-based or keep-whole agreements. Under our fee-based agreements, the amount of fee-based revenue we generate is based on the volumes of natural gas that we process at our processing complexes. Under our keep-whole agreements, we generate revenue based on the difference between our NGL product sales price, the purchase price of natural gas and transportation and fractionation costs. These processing agreements accounted for approximately 45% of our processing throughput for the three months ended March 31, 2014. For the three months ended March 31, 2014, QEP accounted for approximately 51% of our processing revenue.

Under an agreement effective August 14, 2013, QEPM Gathering I, LLC assigned to us its conditioning and keep-whole processing rights that are set forth in certain underlying gas gathering agreements. Pursuant to the terms of the Gas Conditioning Agreement, we receive, condition and deliver natural gas on behalf of QEPM Gathering I, LLC, which allows QEPM Gathering I, LLC to meet its commitments under the underlying gathering contracts. We generate revenue under the Gas Conditioning Agreement based on the difference between our NGL product sales price, the purchase price of natural gas and transportation and fractionation costs.

Our Board will adopt a written related person transaction policy, effective upon the completion of the spin-off, which will set forth the policies and procedures for the review and approval or ratification of related person transactions. This policy will be administrated by our Board. These policies will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the relevant facts and circumstances available shall be considered, including, among other factors it deems appropriate, whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and the extent of the related person’s interest in the transaction.

Prior to the spin-off, we intend to enter into the Credit Facility, which will be a $ million senior secured revolving credit facility. At the closing of the spin off, 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. As the terms of the credit agreement governing the Credit Facility are finalized, we will provide the required and appropriate information in subsequent amendments to the Form 10 to which this information statement is an exhibit.

The following is a description of the material terms of our capital stock as to be provided in our amended and restated certificate of incorporation and amended and restated bylaws, as each is anticipated to be in effect upon the completion of the spin-off. We also refer you to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which will be filed as exhibits in an amendment to the registration statement of which this information statement forms a part.

Following completion of the spin-off, our authorized capital stock will consist of (i) shares of common stock, par value $0.01 per share and (ii) shares of preferred stock, par value $0.01 per share.

Authorized but unissued shares of our capital stock may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions. The DGCL does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the NYSE, which would apply so long as our common stock is listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of common stock.

Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. This means that the holders of a majority of the voting power of the shares voting for the election of directors can elect all directors to be elected if they choose to do so, subject to any voting rights granted to holders of any preferred stock. Except as set forth in the Certificate of Incorporation and Bylaws, all matters to be voted on by stockholders must be approved by a majority of the total voting power of the common stock present in person or represented by proxy at a meeting at which a quorum exists, subject to any voting rights granted to holders of any preferred stock. Except as otherwise provided by law or in the amended and restated certificate of incorporation, and subject to any voting rights granted to holders of any outstanding preferred stock, amendments to the amended and restated certificate of incorporation must be approved by a majority of the votes entitled to be cast by the holders of common stock.

Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board in its discretion may declare out of funds legally available for the payment of dividends. Dividends on our common stock will be paid at the discretion of our Board after taking into account various factors, including:

On liquidation, dissolution or winding up of Entrada, after payment in full of the amounts required to be paid to holders of preferred stock, if any, all holders of common stock are entitled to receive the same amount per share with respect to any distribution of assets to holders of shares of common stock.

No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

Upon completion of the spin-off, all the outstanding shares of our common stock will be validly issued, fully paid and nonassessable.

Our amended and restated certificate of incorporation authorizes our Board to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action by you. Our Board is able to determine, with respect to any series of preferred stock, the terms and rights of that series, including the following:

Some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make the following more difficult:

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions also are designed to encourage persons seeking to acquire control of us to first negotiate with our Board. We believe that the benefits of the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure our company outweigh the disadvantages of discouraging those proposals because negotiation of them could result in an improvement of their terms.

Our amended and restated certificate of incorporation will provide that our Board will be divided into three classes. The term of the first class of directors will expire at our 2015 annual meeting of stockholders, the term of the second class of directors expires at our 2016 annual meeting of stockholders and the term of the third class of

directors expires at our 2017 annual meeting of stockholders. At each of our annual meetings of stockholders, the successors of the class of directors whose term expires at that meeting of stockholders will be elected for a three-year term, one class being elected each year by our stockholders. This system of electing and removing directors may discourage a third-party from making a tender offer or otherwise attempting to obtain control of us because it generally makes it more difficult for stockholders to replace a majority of our directors.

A director nominee shall be elected to our Board if the votes cast for such nominee’s election exceed the votes cast against such nominee’s election. Our amended and restated certificate of incorporation will require that directors may only be removed for cause and only by the affirmative vote of not less than 80% of votes entitled to be cast by the outstanding capital stock in the election of our Board.

Our amended and restated certificate of incorporation will provide that the number of directors on our Board will be fixed exclusively by our Board. Newly created directorships resulting from any increase in our authorized number of directors will be filled solely by the vote of our then current directors in office. Any vacancies in our Board resulting from death, resignation, retirement, disqualification, removal from office or other cause will be filled solely by the vote of our remaining directors in office.

Our amended and restated certificate of incorporation will not provide our stockholders with the ability to act by written consent.

Our amended and restated certificate of incorporation and amended and restated bylaws will provide that a special meeting of our stockholders may be called only by (i) our Board, or (ii) the chairman of our Board with the concurrence of a majority of our Board.

Our amended and restated certificate of incorporation and amended and restated bylaws will provide that the provisions of our bylaws relating to the calling of meetings of stockholders, notice of meetings of stockholders, stockholder action by written consent, advance notice of stockholder business or director nominations, the authorized number of directors, the classified board structure, the filling of director vacancies or the removal of directors (and any provision relating to the amendment of any of these provisions) may only be amended by the vote of a majority of our entire Board or by the vote of holders of at least 80% of the votes entitled to be cast by the outstanding capital stock in the election of our Board.

The amendment of any of the above provisions in our amended and restated certificate of incorporation will require approval by the vote of a majority of our entire Board followed by the vote of holders of at least 80% of the votes entitled to be cast by the outstanding capital stock in the election of our Board.

Requirements for Advance Notification of Stockholder Nominations and Proposals

Our amended and restated bylaws will establish advance notice procedures with respect to stockholder proposals and nomination of candidates for election as directors other than nominations made by or at the direction of our Board or a committee of our Board.

Our amended and restated certificate of incorporation and amended and restated bylaws will not provide for cumulative voting in the election of directors.

The authorization of our undesignated preferred stock makes it possible for our Board to issue our preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes of control of our management.

Section 203 of the DGCL will apply to us. Subject to specific exceptions, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless:

“Business combinations” include mergers, asset sales and other transactions resulting in a financial benefit to the “interested stockholder.” Subject to various exceptions, an “interested stockholder” is a person who, together with his or her affiliates and associates, owns, or within the previous three years did own, 15% or more of the corporation’s outstanding voting stock. These restrictions could prohibit or delay the accomplishment of mergers or other takeover or change in control attempts with respect to us and, therefore, may discourage attempts to acquire us.

The DGCL authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breaches of directors’ fiduciary duties. Under our amended and restated certificate of incorporation, subject to limitations imposed by the DGCL, no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

Our amended and restated bylaws provide that we must indemnify our directors and officers to the fullest extent authorized by the DGCL, and allow us to enter into indemnification agreements with them. We are also expressly authorized to advance certain expenses (including attorneys’ fees and disbursements and court costs) and carry directors’ and officers’ insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that indemnification provisions and insurance are useful to attract and retain qualified directors and executive officers. There is currently no pending material litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought.

Except for the issuance of 10,000 shares of our common stock to QEP in June 2013, we have not issued any securities in unregistered transactions. The issuance of the shares to QEP was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) thereof.

Wells Fargo Shareowner Services will be the transfer agent and registrar for our common stock.

Following the spin-off, we expect to have our common stock listed on the New York Stock Exchange under the symbol “EMID.”

We intend to file with the SEC a registration statement on Form 10 for the shares of common stock that QEP stockholders will receive in the distribution. This information statement does not contain all of the information contained in the Form 10 and the exhibits to the Form 10. We have omitted some items in accordance with the rules and regulations of the SEC. For additional information relating to us and the spin-off, we refer you to the Form 10 and its exhibits, which are on file at the offices of the SEC. Statements contained in this information statement about the contents of any contract or other document referred to may not be complete, and in each instance, if we file the contract or document as an exhibit to the Form 10, we refer you to the copy of the contract or other documents upon such filing. We qualify each statement in all respects by the relevant reference.

You may inspect and copy the Form 10 and exhibits that we intend to file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the Public Reference Room. In addition, the SEC maintains an Internet site at www.sec.gov, from which you can electronically access the Form 10, including its exhibits.

We maintain a website on the Internet at www. .com. We do not incorporate our Internet site, or the information contained on that site or connected to that site, into the information statement or our Registration Statement on Form 10.

As a result of the distribution, we will be required to comply with the full informational requirements of the Exchange Act. We will fulfill those obligations with respect to these requirements by filing periodic reports and other information with the SEC.

We plan to make available, free of charge, on our Internet site our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, reports filed under Section 16 of the Exchange Act and amendments to those reports as soon as reasonably practicable after we electronically file or furnish those materials to the SEC.

You should rely only on the information contained in this information statement or to which we have referred you. We have not authorized any person to provide you with different information or to make any representation not contained in this information statement.

Some of the information in this information statement 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 information statement. The risk factors and other factors noted throughout this information statement 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:

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.

Set forth below are the unaudited pro forma combined statement of operations of Entrada Midstream, Inc. (“Entrada,” “EMID,” the “Company,” “we,” “us” and “our”) for the three months ended March 31, 2014, and the year ended December 31, 2013, and the unaudited pro forma combined balance sheet of the Company as of March 31, 2014. Our pro forma combined financial data has been derived from adjusting the historical combined financial statements of QEP Field Services Company (“QEPFS”) as reported under QEP Resources, Inc. (“QEP”), which consists of our assets and ownership interests as well as the Haynesville gathering system (“Haynesville Gathering System”), which we will transfer to QEP in connection with the spin-off. Immediately prior to the completion of the spin-off, QEPFS will change its name to Entrada, a Delaware corporation. The spin-off will be recorded at historical cost as it will be considered a reorganization of entities under common control.

The historical combined financial statements of QEPFS are set forth elsewhere in this information statement, and the pro forma combined financial data 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. The unaudited pro forma combined financial data may not be indicative of the results that actually would have occurred if we operated autonomously or as an entity independent of QEP in the periods for which historical financial data is presented below or indicative of the results that would be obtained in the future. 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 spin-off had taken place on March 31, 2014, in the case of the pro forma balance sheet, and as of January 1, 2013, in the case of the pro forma income statements for the year ended December 31, 2013, and the three months ended March 31, 2014. The unaudited pro forma financial data gives pro forma effect to the matters described in the notes hereto, including:

The Separation and Distribution Agreement, the Tax Sharing Agreement, the Transition Services Agreement and the Employee Matters Agreement have not been finalized, and the effects of those agreements are therefore not reflected in the pro forma financial statements. To the extent appropriate, the pro forma financial statements will be revised in future amendments to the registration statement of which this information statement is a part to reflect any material impacts of those agreements.

The unaudited pro forma combined financial data does not give effect to incremental annual general and administrative expenses that we expect to incur as a result of being an independent publicly traded company. We are in the process of determining the incremental general and administrative expenses that we expect to incur and will provide an estimated range in a later filing.

The historical financial information of QEPFS included in these unaudited pro forma combined financial statements of Entrada is derived from the audited historical combined financial statements of QEPFS as reported under QEP. Upon completion of this spin-off, we anticipate incurring incremental general and administrative expense as a result of being an independent publicly traded company, including expenses associated with annual, quarterly and current reporting; tax returns; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; 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.

The pro forma adjustments are based on currently available information and certain estimates and assumptions; therefore, the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

The following adjustments have been prepared as if the spin-off and related transactions had taken place at January 1, 2013, in the case of the pro forma income statements and on March 31, 2014, in the case of the pro forma balance sheet.

(b) Reflects the adjustment to noncontrolling interest to reflect QEP Midstream Partner’s initial public offering as if it had occurred January 1, 2013.

(c) Reflects the adjustment to noncontrolling interest to reflect Entrada’s sale of a 40% interest in Green River Processing to QEPM as if it had occurred on January 1, 2013. The sale expected to close in July 2014. Also reflects the $230.0 million adjustment to long-term debt to reflect the borrowing under QEPM’s credit facility, which will be used to fund the transaction.

(d) Reflects the elimination of historical interest expense due to the repayment of $1.5 million of related party, long-term debt with QEP during the year ended December 31, 2013, and the additional interest expense that would have occurred for adjustments discussed in (b) and (c) of $0.9 million for the three months ended March 31, 2014, and $5.2 million for the year ended December 31, 2013.

(e) Reflects the estimated interest expense on $ million of debt from the revolving credit facility. The interest expense was calculated with an assumed interest rate of % and also includes estimated amortization of approximately $ million of deferred finance costs.

(f) Reflects the $ million of debt borrowed under the new revolving credit facility as discussed in (e).

(g) Reflects a one-time cash dividend to QEP of $ million from the amount borrowed under the new revolving credit facility.

(h) Reflects the payment of $ million of estimated fees and expenses associated with Entrada entering into the revolving credit facility. These costs are deferred and amortized over the term of the credit agreement.

(i) Reflects the expected distribution of million shares of Entrada common stock to holders of QEP common stock and the elimination of QEP’s net investment in Entrada.

(j) Pro forma basic earnings per share and shares outstanding are based on the number of shares of Entrada common stock assumed to be outstanding on the spin-off based on a distribution ratio of shares of Entrada common stock for every shares of QEP common stock outstanding. Pro forma diluted earnings per share and diluted shares outstanding are based on the number of share of Entrada common stock outstanding and diluted shares of common stock assumed to be outstanding on the spin-off based on a distribution ratio of shares of Entrada common stock for every shares of QEP common stock outstanding. This calculation may not be indicative of the dilutive effect that will actually result from the replacement of QEP stock based compensation or the grant of new stock based awards and will not be determined until after the first trading day following the spin-off.

(k) Reflects the income tax impacts of the adjustments of the transaction described above.

(l) Reflects the reclassification of activity and balances with QEP from related party to third-party.

In our opinion, the accompanying combined balance sheets and the related combined statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of QEP Field Services Company at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 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.

QEP Field Services Company (“QEPFS”, the “Company,” “we,” “us” and “our”) is a Delaware corporation that owns and operates a diversified portfolio of midstream energy assets. Our business primarily consists of providing natural gas gathering, processing, treating and transportation services and natural gas liquids, or NGL, fractionation and transportation services for our producer customers through our direct ownership and operation of three gathering systems and four processing complexes and one fractionation facility. Our assets, which are strategically located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado and the Uinta Basin located in eastern Utah provide critical infrastructure that links natural gas producers and suppliers to natural gas markets, including various interstate and intrastate pipelines. Finally, we own (i) an approximate 55.8% limited partner interest in QEP Midstream Partners, LP (“QEPM” or “QEP Midstream Partners”), a publicly traded crude oil and natural gas gathering partnership (NYSE: QEPM), consisting of 3,701,750 common units and 26,705,000 subordinated units and (ii) 100% of QEPM’s general partner, which owns the 2.0% general partner interest in QEPM and 100% of QEPM’s incentive distribution rights. QEPM’s assets consist of ownership interests in four gathering systems and two Federal Energy Regulatory Commission (“FERC”) regulated pipelines through which it provides natural gas and crude oil gathering and transportation services.

In December 2013, QEP Resources, Inc. (“QEP”) announced that its board of directors had authorized the separation of QEP’s midstream business, QEPFS including its interest in QEP Midstream Partners. QEP has elected to effect the separation through a spin-off of QEPFS into an independent publicly traded company that is expected to be completed in accordance with a spin-off and distribution agreement (the “spin-off”). Immediately prior to the completion of the spin-off, QEPFS will change its name to Entrada Midstream, Inc. (“Entrada” or “EMID”), a Delaware corporation. The spin-off is intended to be tax free to the stockholders and to QEP and Entrada. QEP intends to distribute, on a pro-rata basis, shares of EMID common stock to QEP stockholders as of the record date for the spin-off. Upon completion of the spin-off, QEP and Entrada will each be independent and have separate public ownership, boards of directors and management. The spin-off will include all of QEPFS’ assets and ownership interests except for the Haynesville Gathering System, which will transfer to QEP in connection with the spin-off. The spin-off is subject to final approval by QEP’s board of directors, which approval is subject to, among other things, an opinion of tax counsel.

These financial statements of QEPFS have been prepared in connection with this information statement and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) on the basis of QEP’s historical ownership of QEPFS’ 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 QEPFS had been operating separately during the periods reported.

The costs of doing business incurred by QEP on our behalf has been reflected in the accompanying financial statements. These costs include general and administrative expenses allocated by QEP to us in exchange for:

Transactions between QEPFS and QEP have been identified in the combined financial statements as transactions between related parties (see Note 4).

The consolidated financial statements contain the accounts of QEPFS and its majority-owned or controlled subsidiaries, including QEPM (see Note 3—QEP Midstream Partners). The consolidated financial statements were prepared in accordance with GAAP. All significant intercompany accounts and transactions have been eliminated in consolidation.

QEPFS uses the equity method to account for investment in unconsolidated affiliates where it does not have control, but has significant influence. The investment in unconsolidated affiliates on our combined balance sheets equals our 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 our 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 QEPFS’ ownership percentage as of December 31, 2013, 2012 and 2011 were Uintah Basin Field Services, L.L.C., in which QEPFS owned a 38% ownership interest and Three Rivers Gathering, L.L.C., in which QEPM currently owns a 50% ownership interest, which was previously owned by QEPFS prior to QEPM’s initial public offering (see Note 3—QEP Midstream Partners). Both are limited liability companies engaged in the gathering and compressing natural gas.

QEPFS provides gathering services, primarily under fee-based contracts, as well as processing services, under keep-whole and fee-based contracts. Under fee-based arrangements, QEPFS receives a fee or fees for one or more of the following services: firm and interruptible gathering of crude oil and natural gas or processing of natural gas. The revenue QEPFS earns from the fee-based arrangements is generally directly related to the volume of oil or gas that flows through QEPFS’ systems or complexes and is not directly dependent on commodity prices. A portion of the fee-based agreements provide for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms.

Under keep-whole arrangements, QEPFS processes the natural gas for a customer and take title to the resulting NGL, which is sold to third parties at market prices. Because the extraction of the NGL from the natural gas during processing reduces the Btu content of the natural gas, QEPFS must either purchase gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this gas. In addition, under the majority of our agreements, QEPFS retains and sells condensate that falls out of the natural gas stream during gathering and processing.

Additionally, we have 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.

The majority of QEPFS’ 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 the commercial-bank accounts that result in available funds the next business day.

QEPFS’ receivables consist primarily of third-party and QEP invoices. QEPFS routinely assesses the recoverability of all material trade and other receivables to determine their collectability. QEPFS’ allowance for bad-debt expense was $2.9 million and $0.4 million as of December 31, 2013, and December 31, 2012, respectively.

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 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 ARO 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.

The combined balance sheets include natural gas imbalance receivables or payables resulting from differences in gas volumes received by customers and gas volumes delivered to interstate pipelines. Natural gas volumes owed to or by QEPFS 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 QEPFS are valued at the Company’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.

the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. See Note 10—Commitments and Contingencies, for additional information.

QEPFS 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.

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.

The customers accounting for 10% or more of QEPFS’ combined revenue for the years ended December 31, 2013, 2012 and 2011 are as follows:

QEPFS’ principal customer for crude oil and natural gas gathering, processing, 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 2013, 2012 and 2011. Management believes that the risk of loss of a large customer is remote as a result of its contractual obligations.

Effective January 1, 2012, we elected to de-designate all of our NGL derivative contracts that were previously designated as cash flow hedges and we elected to discontinue hedge accounting prospectively. Accordingly, all realized and unrealized gains and losses are recognized in earnings immediately as derivative contracts are settled and marked-to-market. At December 31, 2011, AOCI consisted of $0.8 million ($0.5 million after tax) of unrealized gains, representing the mark-to-market value of our cash flow hedges as of the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting, such mark-to-market values at December 31, 2011, were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions occurred and affected earnings. QEP fully reclassified all unrealized gains in AOCI into earnings during 2012.

All of QEP’s derivative contracts are net settled in cash without delivery of product. These contracts also have a nominal quantity, exchange an index price for a fixed price, and are net settled with the brokers as the price bulletins become available. These derivative contracts are recorded in revenue or cost of sales in the month of settlement. These contracts are marked-to-market monthly with any change in the valuation recognized in the determination of income.

QEPFS 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, QEPFS is considered to be participating in the employee benefit plans of QEP. As a participant in the benefit plans, the Company recognizes in each period the allocation from QEP as expense, but it does not recognize any employee benefit plan liabilities.

QEPFS’ 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, QEPFS recognized as expense in each period the allocation from QEP with the offset included in owners’ equity.

ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that our recorded income tax benefits will be fully realized. There were no unrecognized tax benefits at the beginning or end of the twelve-month periods ended December 31, 2013, 2012 and 2011. Federal income tax returns for 2011 and 2012 are closed by the Internal Revenue Service. Income tax returns for 2013 have not yet been filed. Most state tax returns for 2010 and subsequent years remain subject to examination.

Noncontrolling interests represent third-party ownership in the net assets of our combined subsidiaries and are presented as a component of equity and net income. Changes in QEPFS’ ownership interest in subsidiaries that do not result in deconsolidation are recognized in equity. On August 14, 2013, QEPFS completed the initial public offering (“IPO”) of QEPM. Prior to the IPO, QEP’s noncontrolling interest related to the outside ownership of Rendezvous Gas Services, L.L.C. Subsequent to the IPO, QEPM’s results (which include Rendezvous Gas Services, L.L.C) are consolidated into QEPFS as it is a majority-owned and controlled subsidiary and the portion not owned by QEPFS reflected as noncontrolling interest. See Note 3—QEP Midstream Partners for further information regarding the IPO.

We did not have any assets or liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012. We believe the carrying value of our current assets and liabilities approximate fair value. The carrying amount of our long-term debt to related party approximates fair value.

The initial measurement of ARO at fair value is calculated using discontinued 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 ARO and include retirement costs and asset lives. A reconciliation of our ARO is presented in Note 6—Asset Retirement Obligations.

During the year ended December 31, 2013, there were no new accounting pronouncements that were applicable to QEPFS.

QEP Midstream Partners is a publicly traded master limited partnership that was formed by QEPFS to own, operate, acquire and develop midstream energy assets. QEPM’s assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

On August 14, 2013, QEP Midstream completed its IPO of 20,000,000 common units, representing limited partner interests in QEPM, at a price to the public of $21.00 per common unit. QEPM received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters’ discounts and commissions and structuring fees, to QEPM.

QEPM used the net proceeds to repay its outstanding debt balance with QEPFS, which was assumed with the assets contributed to QEPM, pay revolving credit facility origination fees and make a cash distribution to QEPFS, a portion of which was used to reimburse QEPFS for certain capital expenditures it incurred with respect to assets contributed to QEPM. The following table is a reconciliation of proceeds from the IPO (in millions):

QEP Midstream Partners GP, LLC (the General Partner), a wholly owned subsidiary of QEPFS, serves as the general partner of QEPM. QEPFS owns a 57.8% interest in QEPM and consolidates QEPM for financial reporting purposes with the portion not owned by QEPFS reflected as a reduction to net income and equity as a noncontrolling interest.

The following agreements were entered into between QEPFS and QEPM in connection with the IPO.

In connection with the IPO, QEPFS entered into a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) with the General Partner and QEP Midstream Partners Operating, LLC (the “Operating Company”). Immediately prior to the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

In connection with the IPO, QEPFS entered into an Omnibus Agreement (the “Omnibus Agreement”) with QEPM, that addresses the following matters:

As long as QEPFS controls the General Partner, the Omnibus Agreement will remain in full force and effect. If QEPFS ceases to control the General Partner, either party may terminate the Omnibus Agreement, but the indemnification obligations will remain in full force and effect in accordance with their terms.

QEPFS provides crude oil and gas gathering, processing, treating and transportation services, NGL, fractionation and transportation services, and gathering and transportation services to QEP resulting in related party transactions. The following discussion describes these related party transactions in more detail.

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.

In 2011, QEPFS had a $250.0 million revolving debt agreement (the “2011 Agreement”) with QEP for its funding shortfalls, in which QEPFS was charged a variable interest rate. Interest in 2011 and a portion of 2012 was allocated to QEPFS based on an interest rate equal to QEP’s average borrowing rate, which was 5.9% in 2011. In April 2012, QEPFS entered into new debt agreements with QEP replacing the 2011 Agreement with a $250.0 million promissory note that matured on April 1, 2014. In addition, QEPFS entered into a $1.0 billion “revolving credit” type promissory note to fund capital expenditures that matures in March 2017. QEPFS 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 QEPFS to pay QEP interest at a 6.05% fixed-rate in 2012. Interest allocated to QEPFS under these notes in 2012 was based on the fixed-rate due to QEP. QEPFS was compliant with its covenants under the agreement at December 31, 2013, and there are no letters of credit outstanding. At December 31, 2012, allocated debt outstanding for QEPFS was $199.5 million. There was no debt outstanding as of December 31, 2013.

The employees supporting QEPFS’ operations are employees of QEP. General and administrative expense allocated to QEPFS was $47.5 million, $35.3 million and $33.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. The combined financial statements of QEPFS 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.

The following table summarizes the related party income statement transactions with QEP:

A summary of the historical cost of QEPFS’ property, plant and equipment is as follows:

QEPFS 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 QEPFS 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 QEPFS.

The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:

QEPFS has periodically used commodity price derivative instruments to manage commodity price volatility on a portion of its extracted NGL volumes. The volume of production subject to commodity derivative instruments and the mix of the instruments are evaluated and adjusted by management in response to changing market conditions. QEPFS does not enter into commodity derivative instruments for speculative purposes.

QEPFS uses commodity derivative instruments, typically structured as Mont Belvieu, Texas, fixed-price swaps. QEPFS’ commodity derivative instruments do not require the physical delivery of NGL between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period.

QEPFS enters into commodity derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEPFS routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties.

Effective January 1, 2012, QEPFS elected to de-designate all of its NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in AOCI as of the de-designation date and reclassified into the Combined Statement of Operations as the transactions settled and affected earnings. During the year ended December 31, 2012, the remaining portion of unrealized gains fixed in AOCI of $8.4 million, net of tax, were settled and reclassified to the Combined Statements of Operations. There were no outstanding derivatives as of December 31, 2013. All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012 are presented in the Combined Statements of Operations in “Realized gains on derivative instruments” below operating income.

The effects of the change in fair value and settlement of QEPFS’ derivative contracts recorded in “Realized gains on derivative instruments” on the Combined Statements of Operations are summarized in the following tables:

The following table presents the change in the fair value and settlement of QEPFS’ derivative contracts that were designated as cash flow hedges in 2011:

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEPFS. In connection with this announcement, the Board of Directors approved an employee retention plan to provide substantially all QEPFS’ employees as of December 1, 2013, with a one-time lump-sum cash payment on December 31, 2014, or whenever the separation of QEPFS occurs, whichever is earlier, conditioned on continued employment with QEPFS or a successor through the payment date unless the employee is terminated prior to such date.

The total amount QEPFS expects to incur with regards to this restructuring is $10.1 million. This amount is related entirely to the employee retention plan discussed above. As of December 31, 2013, QEPFS has incurred $0.8 million which has been expensed but has not been paid or settled and is included in “Accounts payable” on the Combined Balance Sheets.

On August 14, 2013, QEPM entered into a $500.0 million senior secured revolving credit facility with a group of financial institutions, which matures on August 14, 2018. QEPM’s credit facility contains an accordion provision that allows for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. QEPM’s credit facility is available for QEPM’s working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of QEPM’s assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the credit facility. In addition, the credit facility contains restrictions and events of default customary for agreements of this nature.

There have been no borrowings under QEPM’s credit facility, and at December 31, 2013, QEPM was in compliance with the covenants under the QEPM credit facility agreement. All additional debt outstanding relates to intercompany debt with QEP discussed in Note 4—Related Party Transactions.

QEPFS is not a borrower or guarantor of QEPM’s credit facility. In addition, QEPFS is not subject to any of the restrictions or covenants contained in QEPM’s credit agreement. Outstanding indebtedness under QEPM’s credit facility is not included in the definition of indebtedness under QEP’s credit facility.

We are involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of our business. We assess these claims in an effort to determine the degree of

probability and range of possible loss for potential accrual in our 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, we 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 matter. QEPFS’ litigation loss contingencies are discussed below. We are unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. We believe, however, that after consideration of accrued amounts, insurance coverage and indemnification arrangements, the resolution of pending proceedings will not have a material effect on our financial position, results of operations or cash flows.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate, Questar Gas Company (“QGC”), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the “1993 Agreement”) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services’ systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the IPO, the assets and the 1993 Agreement discussed above were assigned to QEPM. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEPM. As of December 31, 2013, QEP Field Services has recorded $8.5 million of deferred revenue related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEPM as a defendant in the litigation. QEPM has been indemnified by QEP for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEPM and QEP in connection with the IPO.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (“XTO”), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the “XTO Agreement”). QEP Field Services processes XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. The plaintiffs seek damages, but specific monetary damages are not asserted.

QEP Field Services has contracted for NGL transportation services with various third-party pipelines. Market conditions and competition may prevent full utilization of the contractual capacity. In addition, QEP Field Services has contracts with third parties who provide fractionation contracts. Annual payments and the corresponding years for transportation contracts and fractionation contracts are as follows (in millions):

QEP has contractual cash obligations for operating leases of which a portion is allocated to QEPFS. 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 $1.2 million, $1.0 million and $0.6 million for 2013, 2012 and 2011, respectively. Allocated annual payments and the corresponding years for operating lease contracts are as follows (in millions):

Details of income tax expenses and deferred income taxes from continuing operations are provided in the following tables. The components of income tax expenses were as follows:

The difference between the statutory federal income tax rate and the Company’s effective income tax rate is explained as follows:

Taxes are calculated on a separate return basis, rather than allocated from QEP. QEPFS has been included in QEP’s consolidated U.S. tax return. QEPFS is jointly (with other subsidiaries of QEP), and severally liable for any additional taxes that may be assessed.

In May 2014, QEPFS entered into a purchase and sale agreement to sell 40% of Green River Processing, LLC (“Green River Processing”) for approximately $230.0 million, subject to customary purchase price adjustments, to QEPM. The transaction is expected to close in July 2014 and will be accounted for as a transaction between entities under common control with the difference between the carrying amount and the purchase price recorded to equity.

Green River Processing is a wholly owned subsidiary of QEPFS and will own the Blacks Fork complex and the Emigrant Trail plant, both of which are located in southwest Wyoming. The combined processing capacity of Green River Processing is up to 890 MMcf/d, of which up to 560 MMcf/d is cryogenic capacity and 330 MMcf/d is Joule-Thomson processing capacity. In addition, there is 15,000 Bbl/d of NGL fractionation capacity at the Blacks Fork complex.

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 financial statements. These financial statements should be read in conjunction with QEPFS’ combined financial statements for the year ended December 31, 2013. These financial statements reflect all normal 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 QEPFS have been prepared in connection with this information statement and have been prepared in accordance with GAAP on the basis of QEP’s historical ownership of QEPFS’ 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 QEPFS had been operating separately during the periods reported.

Transactions between QEPFS and QEP have been identified in the combined financial statements as transactions between related parties (see Note 2).

On August 14, 2013, QEPM completed its initial public offering (“IPO”) of 20,000,000 common units, representing limited partner interests in QEPM, at a price to the public of $21.00 per common unit. QEPM received net proceeds of $390.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $29.3 million. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing additional net proceeds of $58.9 million, after deducting $4.1 million of underwriters’ discounts and commissions and structuring fees, to QEPM. QEPM used the net proceeds to repay its outstanding debt balance with QEPFS, which was assumed with the assets contributed to QEPM, pay revolving credit facility origination fees and make a cash distribution to QEPFS, a portion of which was used to reimburse QEPFS for certain capital expenditures it incurred with respect to assets contributed to QEPM.

QEPM is a publicly traded master limited partnership that was formed by QEPFS to own, operate, acquire and develop midstream energy assets. QEPM’s assets currently consist of ownership interests in four gathering systems and two FERC regulated pipelines, which provide oil and gas gathering and transportation services. These assets are located in, or within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

During the three months ended March 31, 2014, there were no new accounting pronouncements that were applicable to QEPFS.

QEPFS provides gas gathering, processing, treating and transportation services and NGL, fractionation and transportation services to QEP resulting in related party transactions. The following discussion describes these related party transactions in more detail.

During 2013, QEP Field Services had a $250.0 million promissory note with QEP, which matured at the end of the first quarter of 2013 with a fixed interest rate of 6.05%. The promissory note was renewed on April 1, 2013, and matured on April 1, 2014. In addition, QEP Field Services entered into a $1.0 billion revolving credit type promissory note with QEP, with a maturity date of April 1, 2017, to assist with funding of capital expenditures. QEPFS has the ability and intent to refinance the promissory note on a long-term basis under the $1.0 billion promissory note. Both agreements required QEPFS to pay QEP interest at a 6.05% fixed-rate in 2013 and all interest expense was due to QEP and settled in cash. QEPFS was compliant with its covenants under the agreement at March 31, 2014, and there are no letters of credit outstanding. As of March 31, 2014 and December 31, 2013, QEPFS had no outstanding debt.

The employees supporting the QEPFS’ operations are employees of QEP. General and administrative expense allocated to QEPFS was $14.5 million and $10.8 million for the three months ended March 31, 2014 and 2013, respectively. The combined financial statements of QEPFS 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 QEPFS 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:

A summary of the historical cost of QEPFS’ property, plant and equipment is as follows:

QEPFS records asset retirement obligations (“ARO”) when there are legal obligations associated with the retirement of tangible long-lived assets. The fair values of such costs are estimated by QEPFS 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 QEPFS.

The following is a reconciliation of the changes in the asset retirement obligation for the periods specified below:

The total amount QEPFS expects to incur with regards to this restructuring is $10.1 million. This amount is related entirely to the employee retention plan discussed above. As of March 31, 2014, QEPFS has incurred $3.1 million which has been expensed but has not been paid or settled and is included in “Accounts payable” on the Combined Balance Sheets.

There have been no borrowings under QEPM’s credit facility, and at March 31, 2014, QEPM was in compliance with the covenants under the QEPM credit facility agreement.

QEPFS is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEPFS 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, QEPFS 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. QEPFS’ litigation loss contingencies are discussed below. QEPFS is unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. QEPFS believes, however, that the resolution of pending proceedings will not have a material effect on the QEPFS’ financial position, results of operations or cash flows.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate, Questar Gas Company (“QGC”), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the “1993 Agreement”) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services’ systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the IPO, the assets and the 1993 Agreement discussed above were assigned to QEPM. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEPM. As of March 31, 2014, QEPM has deferred revenue of $9.9 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add QEPM as a defendant in the litigation. QEPM has been indemnified by QEP for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEPM and QEP in connection with the IPO.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (“XTO”), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the “XTO Agreement”). QEP Field Services processes XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is disputing QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. The plaintiffs seek damages, but specific monetary damages are not asserted.

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.

life-of-reserves contract: A contract that remains in effect as long as commercial production of hydrocarbons is ongoing.

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 hydrocarbon-based products transported or passing through a pipeline, plant, terminal or other facility during a particular period.


Potential Payments Upon Termination or Change in Control			129
Our Equity Plans Following the Spin-Off			130
Director Compensation			130

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			131

ARRANGEMENTS BETWEEN QEP AND OUR COMPANY AND OTHER RELATED PARTY TRANSACTIONS			132

The Separation from QEP			132
Agreements Between QEP and Us			133

DESCRIPTION OF MATERIAL INDEBTEDNESS			135

DESCRIPTION OF CAPITAL STOCK			136

Authorized Capitalization			136
Common Stock			136
Preferred Stock			137
Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions			137
Delaware Anti-Takeover Statute			139
Limitations on Liability and Indemnification of Officers and Directors			139
Recent Sale of Unregistered Securities			140
Transfer Agent and Registrar			140
Listing			140

WHERE YOU CAN FIND ADDITIONAL INFORMATION			141

FORWARD-LOOKING STATEMENTS			142

INDEX TO FINANCIAL STATEMENTS			F-1

APPENDIX B GLOSSARY OF TERMS			B-1


	As of March 31, 2014
	Historical		Pro Forma
	(in millions)
Cash and cash equivalents	$	20.2

Long-term debt
Credit facility		—

Total long-term debt		—

Equity
Owners’ net investment		615.9
Common stock, at par value
Noncontrolling interest		498.4

Total equity	$	1,114.3

Total capitalization	$	1,114.3


	Three Months Ended March 31,					Change
	2014			2013		2014 vs 2013
	(in millions)
Net income	$	28.1		$	30.1	$	(2.0	)
Non-cash adjustments to net income		19.8			19.2		0.6
Changes in operating assets and liabilities		(24.1	)		42.6		(66.7	)

Net cash provided from operating activities	$	23.8		$	91.9	$	(68.1	)


	Year Ended December 31,							Change
	2013		2012			2011		2013 vs 2012			2012 vs 2011
	(in millions)
Total accrual capital expenditures	$	75.6	$	170.2		$	108.3	$	(94.6	)	$	61.9
Change in accruals and non-cash items		6.4		(3.9	)		19.3		10.3			(23.2	)

Total cash capital expenditures	$	82.0	$	166.3		$	127.6	$	(84.3	)	$	38.7


	Payments Due by Year
	Total		2014		2015		2016		2017		2018		After 2018
	(in millions)
NGL transportation	$	344.0	$	43.0	$	43.0	$	43.0	$	43.0	$	43.0	$	129.0
NGL fractionation		113.9		14.2		14.2		14.2		14.2		14.2		42.9
Asset retirement obligations⁽¹⁾		32.4		—		—		—		—		—		32.4
Operating leases⁽²⁾		11.8		1.5		1.4		1.4		1.4		1.1		5.0

Total	$	502.1	$	58.7	$	58.6	$	58.6	$	58.6	$	58.3	$	209.3


	Page
SUMMARY		1

Entrada Midstream, Inc.		1
Our Assets and Operations		3
Business Strategies		7
Other Information		8
Our Emerging Growth Company Status		9
The Spin-Off		9
Risk Factors		10
Questions and Answers about the Spin-off		11
Organizational Structure of Entrada Midstream, Inc.		17
Summary of the Spin-Off		18

SUMMARY HISTORICAL AND PRO FORMA COMBINED FINANCIAL AND OPERATING DATA		21

RISK FACTORS		23

Risks Related to Our Business		23
Risks Related to the Spin-Off		38
Risks Related to Our Common Stock		43

THE SPIN-OFF		46

Background		46
Reasons for the Spin-Off		46
Manner of Effecting the Spin-Off		47
Treatment of Fractional Shares		48
U.S. Federal Income Tax Consequences of the Spin-Off		48
Results of the Spin-Off		52
Trading Prior to the Distribution Date		52
Treatment of Stock-Based Plans for Current and Former Employees		53
Incurrence of Debt		53
Conditions to the Spin-Off		53
Reason for Furnishing this Information Statement		54

TRADING MARKET		55

Market for Our Common Stock		55
Transferability of Shares of Our Common Stock		55

DIVIDEND POLICY		57

CAPITALIZATION		58

SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL AND OPERATING DATA		59

Non-GAAP Financial Measures		61

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		62

Overview		62
Our Operations		62
How We Evaluate Our Business		63
General Trends and Outlook		64


Factors Affecting the Comparability of Our Financial Results			66
Results of Operations			67
Liquidity and Capital Resources			73
Cash Flow			73
Credit Facility			75
Off-Balance Sheet Arrangements			75
Credit Risk			75
Contractual Cash Obligations and Other Commitments			76
Related Parties			76
Critical Accounting Policies and Estimates			76
Quantitative and Qualitative Disclosures About Market Risk			79

INDUSTRY OVERVIEW			80

General			80
Natural Gas Midstream Services			80
Crude Oil Gathering and Transportation			81
Contractual Arrangements			82
U.S. Natural Gas Fundamentals			83

BUSINESS			86

Overview			86
Business Strategies			87
Competitive Strengths			88
Our Assets and Operations			88
Competition			104
Seasonality			104
Insurance			104
Safety and Maintenance			105
Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service			107
Environmental Matters			110
Title to Properties and Permits			114
Employees			115
Legal Proceedings			115

MANAGEMENT			117

Executive Officers			117
Board of Directors			117
Board Composition			117
Board Committees			117
Compensation Committee Interlocks and Insider Participation			119
Code of Ethics			119

EXECUTIVE COMPENSATION			120

Summary Compensation Table			120
Outstanding Equity Awards at Fiscal Year-End 2013			122
Compensation Elements			123
2013 Total Compensation Targets by NEO			124
QEP’s Annual Incentive Program (AIP)			125
Long-Term Incentives			126
Retirement Plans			128


	QEPFS Historical															Entrada Pro Forma
	Year Ended December 31,									Three Months Ended March 31,						Three Months Ended March 31,	Year Ended December 31,
	2013⁽¹⁾			2012			2011			2014			2013			2014	2013
	(in millions)
*Reconciliation of Net Income Attributable to us to Adjusted EBITDA*
Net income attributable to us	$	105.0		$	133.1		$	147.3		$	22.4		$	29.5
Interest expense, net		3.1			10.9			16.8			0.6			1.3
Noncontrolling interest share of interest expense⁽²⁾		(0.4	)		—			—			(0.2	)		—
Interest and other income		(1.2	)		(0.1	)		(0.1	)		—			(0.3	)
Income taxes		59.2			74.1			89.2			12.8			17.0
Depreciation and amortization		63.8			63.9			55.1			16.5			15.7
Noncontrolling interest share of depreciation and amortization⁽³⁾		(6.8	)		(2.8	)		(2.7	)		(3.7	)		(0.7	)
Net loss from asset sales		0.5			—			—			—			0.3

Adjusted EBITDA	$	223.2		$	279.1		$	305.6		$	48.4		$	62.8


	Year Ended December 31,									Change						Three Months Ended March 31,						Change
	Year Ended December 31,									2013 vs 2012			2012 vs 2011			Three Months Ended March 31,						2014 vs 2013
	2013			2012			2011			2013 vs 2012			2012 vs 2011			2014			2013			2014 vs 2013
	(in millions)
Revenue
NGL sales	$	105.2		$	136.6		$	214.9		$	(31.4	)	$	(78.3	)	$	33.1		$	24.3		$	8.8
Processing (fee-based) revenue		74.0			69.7			52.6			4.3			17.1			16.9			16.4			0.5
Other processing revenue		13.2			8.9			2.4			4.3			6.5			8.1			4.9			3.2
Gathering revenue		152.2			171.7			161.0			(19.5	)		10.7			33.2			38.5			(5.3	)
Other gathering revenue		50.5			37.9			35.3			12.6			2.6			11.2			10.4			0.8
Purchased gas and NGL sales		8.6			13.2			—			(4.6	)		13.2			0.8			5.1			(4.3	)

Total revenue		403.7			438.0			466.2			(34.3	)		(28.2	)		103.3			99.6			3.7

Operating expenses
Purchased gas and NGL expense		9.0			12.0			—			(3.0	)		12.0			0.3			5.1			(4.8	)
Processing expense		16.1			16.6			12.4			(0.5	)		4.2			4.6			3.3			1.3
Processing plant fuel and shrinkage		32.2			33.4			59.7			(1.2	)		(26.3	)		10.8			6.3			4.5
Gathering expense		39.7			36.9			35.3			2.8			1.6			10.0			9.7			0.3
NGL transportation and fractionation costs		16.3			27.3			12.0			(11.0	)		15.3			5.5			0.4			5.1
General and administrative		47.5			35.3			33.9			12.2			1.4			14.5			10.8			3.7
Taxes other than income taxes		6.6			6.5			5.8			0.1			0.7			1.8			1.2			0.6
Depreciation and amortization		63.8			63.9			55.1			(0.1	)		8.8			16.5			15.7			0.8

Total operating expenses		231.2			231.9			214.2			(0.7	)		17.7			64.0			52.5			11.5
Net loss from property sales		(0.5	)		—			—			(0.5	)		—			—			(0.3	)		0.3

Operating income		172.0			206.1			252.0			(34.1	)		(45.9	)		39.3			46.8			(7.5	)
Interest and other income		1.2			0.1			0.1			1.1			—			—			0.3			(0.3	)
Income from unconsolidated affiliates		6.1			7.2			4.4			(1.1	)		2.8			2.2			1.3			0.9
Realized gains on derivative instruments		—			8.4			—			(8.4	)		8.4			—			—			—
Interest expense, net		(3.1	)		(10.9	)		(16.8	)		7.8			5.9			(0.6	)		(1.3	)		0.7

Income before income taxes		176.2			210.9			239.7			(34.7	)		(28.8	)		40.9			47.1			(6.2	)
Income taxes		(59.2	)		(74.1	)		(89.2	)		14.9			15.1			(12.8	)		(17.0	)		4.2

Net income		117.0			136.8			150.5			(19.8	)		(13.7	)		28.1			30.1			(2.0	)
Net income attributable to noncontrolling interest		(12.0	)		(3.7	)		(3.2	)		(8.3	)		(0.5	)		(5.7	)		(0.6	)		(5.1	)

Net income attributable to us	$	105.0		$	133.1		$	147.3		$	(28.1	)	$	(14.2	)	$	22.4		$	29.5		$	(7.1	)


	Years Ended December 31,									Change						Three Months Ended March 31,						Change
	Years Ended December 31,									2013 vs 2012			2012 vs 2011			Three Months Ended March 31,						2014 vs 2013
	2013			2012			2011			2013 vs 2012			2012 vs 2011			2014			2013			2014 vs 2013
	(in millions)
*Processing Margin*
NGL sales⁽¹⁾	$	105.2		$	136.6		$	214.9		$	(31.4	)	$	(78.3	)	$	33.1		$	24.3		$	8.8
Realized gains from commodity derivative contract settlements		—			8.4			—			(8.4	)		8.4			—			—			—
Processing (fee-based) revenue		74.0			69.7			52.6			4.3			17.1			16.9			16.4			0.5
Other processing revenue		13.2			8.9			2.4			4.3			6.5			8.1			4.9			3.2
Processing expense		(16.1	)		(16.6	)		(12.4	)		0.5			(4.2	)		(4.6	)		(3.3	)		(1.3	)
Processing plant fuel and shrinkage		(32.2	)		(33.4	)		(59.7	)		1.2			26.3			(10.8	)		(6.3	)		(4.5	)
NGL transportation and fractionation costs		(16.3	)		(27.3	)		(12.0	)		11.0			(15.3	)		(5.5	)		(0.4	)		(5.1	)

Processing margin	$	127.8		$	146.3		$	185.8		$	(18.5	)	$	(39.5	)	$	37.2		$	35.6		$	1.6

Keep-whole processing margin⁽²⁾	$	56.7		$	84.3		$	143.2		$	(27.6	)	$	(58.9	)	$	16.8		$	17.6		$	(0.8	)
*Operating Statistics*
Gas processing volumes
NGL sales (Mbbl)		2,250.2			3,486.8			4,009.4			(1,236.6	)		(522.6	)		766.1			483.7			282.4
Average net realized NGL sales price (per bbl)⁽³⁾	$	46.75		$	39.18		$	53.60		$	7.57		$	(14.42	)	$	43.21		$	50.24		$	(7.03	)
Fee-based processing volumes (in millions of MMBtu)		246.5			252.6			246.9			(6.1	)		5.7			55.9			56.0			(0.1	)
Average fee-based processing revenue (per MMBtu)	$	0.30		$	0.28		$	0.21		$	0.02		$	0.07		$	0.30		$	0.29		$	0.01


							Average Recovery⁽²⁾
Asset	Year Built		Facility Type	Inlet Capacity (**MMcf/d)⁽¹⁾**			Ethane			Propane			Normal Butane			Iso Butane			Natural Gasoline
Blacks Fork I		1995	Cryogenic		85			44	%		95	%		99	%		98	%		100	%
Blacks Fork JT		1995/2006	Joule-Thomson		330			0.1	%		4	%		22	%		15	%		46	%
Blacks Fork II⁽³⁾		2011	Cryogenic		420			93	%		100	%		100	%		100	%		100	%
Blacks Fork Fractionator		1995/2013	Fractionator		15,000	⁽⁴⁾

Total			Processing		835

			Fractionation		15,000	⁽⁴⁾


					Average Recovery⁽¹⁾
Asset	Year Built		Inlet Capacity (MMcf/d)⁽²⁾		Ethane			Propane			Normal Butane			Iso Butane			Natural Gasoline
Emigrant Trail Complex		1984		55		89	%		99	%		100	%		100	%		100	%


	Year Built		Inlet Capacity (MMcf/d)⁽²⁾		Average Recovery⁽¹⁾
Asset	Year Built		Inlet Capacity (MMcf/d)⁽²⁾		Ethane			Propane			Normal Butane			Iso Butane			Natural Gasoline
Vermillion Complex		1998/2014		43		40	%		90	%		99	%		98	%		100	%


	Year Built		Facility Type	Inlet Capacity **(MMcf/d)⁽¹⁾**		Average Recovery⁽²⁾
Asset	Year Built		Facility Type	Inlet Capacity **(MMcf/d)⁽¹⁾**		Ethane			Propane			Normal Butane			Iso Butane			Natural Gasoline
Redwash/24B⁽³⁾		2001/2005	Refrigeration		140		1	%		9	%		26	%		20	%		52	%
Stagecoach		2008	Refrigeration		200		1	%		9	%		26	%		20	%		52	%
Ironhorse I		2011	Cryogenic		155		74	%		97	%		100	%		100	%		100	%
Ironhorse II		2013	Cryogenic		155		74	%		97	%		100	%		100	%		100	%

Total					650


Name and Principal Position	Year		Salary		Bonus		Stock Awards		Option Awards		Non-Equity Incentive Plan Compensation		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
			($)		($)		($)⁽¹⁾		($)⁽²⁾		($)⁽³⁾		($)^{(4), (5)}		($)⁽⁶⁾		($)
Charles B. Stanley Chairman, President,		2013		819,167		—		3,286,998		1,533,348		825,000		—		116,817		6,581,330
Charles B. Stanley Chairman, President,		2012		783,333		—		2,766,724		1,309,172		955,900		1,872,501		120,650		7,808,280
and Chief Executive
Officer
Richard J. Doleshek Executive Vice		2013		536,667		—		1,665,261		750,006		486,900		104,412		74,285		3,617,531
Richard J. Doleshek Executive Vice		2012		510,833		—		1,333,335		630,924		560,835		746,772		77,455		3,860,154
President & Chief
Financial Officer
Perry H. Richards Senior Vice President,		2013		298,333		—		455,129		200,003		165,000		—		36,902		1,155,367
Perry H. Richards Senior Vice President,		2012		286,667		—		400,031		189,283		175,450		1,020,443		39,744		2,111,618
QEP Field Services


Name	Performance Share Units ($)^(a),(b)		Restricted Stock ($)^(b)		QEPM Phantom Units ($)^(c)
Charles B. Stanley		1,533,349		1,533,329		220,300
Richard J. Doleshek		750,018		750,018		165,225
Perry H. Richards		200,027		200,027		55,075


										Stock Awards
	Option Awards⁽⁷⁾									Restricted Stock						Performance Share Units
						Option Exercise Price ($)		Option Expiration Date		Shares or Units of Stock that have not Vested (#)			Market Value of Shares or Units of Stock that have not Vested ($)			Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that have not Vested (#)			Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that have not Vested ($)





Name	Shares of Common Stock Underlying Unexercised Options Exercisable (#)		Shares of Common Stock Underlying Unexercised Options Unexercisable (#)
Charles B. Stanley		60,000		—			27.84		2/13/2015		10,807	⁽¹⁾		331,235
		108,000		—			23.98		3/5/2016		10,235	⁽²⁾		313,703
		62,000		—			27.55		3/5/2017		29,846	⁽³⁾		914,780
		42,392		21,1961			39.07		2/25/2018		50,908	⁽⁴⁾		1,560,330
		30,117		60,2333			30.90		2/13/2019		10,000	⁽⁸⁾		232,200			44,769	⁽⁵⁾		1,372,170
		—		100,0884			30.12		2/13/2020								50,908	⁽⁶⁾		1,560,330
Richard J. Doleshek		100,000		—			22.95		5/7/2016		5,261	⁽¹⁾		161,250
		30,000		—			27.55		3/5/2017		6,823	⁽²⁾		209,125
		20,639		10,3191			39.07		2/25/2018		14,383	⁽³⁾		440,839
		14,514		29,0283			30.90		2/13/2019		24,901	⁽⁴⁾		763,216			21,575	⁽⁵⁾		661,274
		—		48,956	⁽⁴⁾		30.12		2/13/2020		7,500	⁽⁸⁾		174,150	⁽⁸⁾		24,901	⁽⁶⁾		763,216
Perry H. Richards		25,000		—			23.98		3/5/2016		1,592	⁽¹⁾		48,795
		15,000		—			27.55		3/5/2017		1,706	⁽²⁾		52,289
		6,248		3,123	⁽¹⁾		39.07		2/25/2018		4,315	⁽³⁾		132,255
		4,355		8,708	⁽³⁾		30.90		2/13/2019		6,641	⁽⁴⁾		203,547			6,473	⁽⁵⁾		198,397
		—		13,055	⁽⁴⁾		30.12		2/13/2020		2,500	⁽⁸⁾		58,0508			6,641	⁽⁶⁾		203,547


Compensation Element		Role in Total Compensation
Base Salary		• Provides fixed compensation based on an individual’s skills, experience and proficiency, market competitive data, and the relative value of the individual’s role.
Annual Incentive Program (AIP)		• Rewards annual performance;
		• Aligns participants’ compensation with short-term financial and operational objectives specific to each calendar year;
		• Motivates participants to meet or exceed internal and external performance expectations;
		• Communicates the compensation committee’s evaluation of annual performance; and
		• Recognizes individual contributions to the organization’s results.
		• Metrics for 2013 included QEP’s Adjusted EBITDA, oil and total production goals as well as the committee’s evaluation of performance on key strategic objectives, including but not limited to the formation of an MLP for midstream assets and execution on QEP’s new Williston Basin assets in North Dakota.
Long-Term Incentives • Performance Share Units • Restricted stock • Stock options		• Rewards long-term performance, directly aligned with shareholder interests;
		• Provides a strong performance-based equity component;
		• Recognizes and rewards share performance relative to industry peers through PSUs based on relative TSR;
		• Aligns compensation with sustained long-term value creation;
		• Allows executives to acquire a meaningful and sustained ownership stake; and
		• Fosters executive retention by vesting awards over multiple years.
Benefits • Health & Welfare • Retirement • Deferred Compensation Benefits • Other		• Helps QEP attract and retain executive talent and remain competitive in our industry by offering a comprehensive employee benefits package;
		• Provides health and welfare benefits comparable to those provided to all other employees;
		• Provides financial security in the event of various individual risks and maximizes the efficiency of tax-advantaged compensation vehicles; and
		• Provides limited perquisites consistent with those offered by peer companies
Termination Benefits		• Attracts and retains executives in a competitive and changing industry
Termination Benefits		• Ensures executives act in the best interests of stockholders in times of heightened uncertainty.


	2012			2013			% Change
Annual Base Salary	$	790,000		$	825,000			4	%
Annual Incentive Target (% of base salary)		100	%		100	%		—
Annual Incentive Target	$	790,000		$	825,000			4	%
Long-Term Incentive Target	$	4,150,000		$	4,600,000			11	%
Total Compensation Target	$	5,730,000		$	6,250,000			9	%


2013 Metric	Weight			50% of Target	100% of Target	150% of Target	200% of Target
AIP-Adjusted EBITDA(1) (in millions)		35	%	$1,540	$1,572	$1,657	$1,765
QEP Energy Oil Production MMbbls		25	%	9.21	10.50	11.98	14.10
QEP Energy Total Production Bcfe		5	%	301.00	315.00	329.00	386.00
Achievement of Strategic Objectives		35	%	Overall assessment of performance:
				• Form an MLP for Wyoming and North Dakota gathering assets;

				• Grow crude oil reserves and production at reasonable and profitable finding and development costs;

				• Optimize corporate financial health;

				• Replace corporate systems to enable timely, accurate and robust financial reporting;

				• Complete accounting group restructuring and ensure all key processes are accurate and timely; and

				• Work safely and respect the environment.


Participants		Employees selected by the Compensation Committee, including the NEOs.
Performance Measure-Relative Total Shareholder Return		The payout is based on QEP’s TSR over the performance period compared to the TSR of a group of peer companies over the same period. TSR combines share price appreciation and dividends paid to determine the total return to the shareholder.
Vesting		PSUs vest at the end of a three year performance period and are payable in cash.
Payout Scale		The payout scale is based on QEP’s percentile rank in the peer group, with interpolation between each point: • 90th percentile or above: 200% payout • 70th Percentile: 150% payout • 50th Percentile: 100% payout • 30th Percentile: 50% payout • Below 30th Percentile: 0% payout
Payout Calculation		The actual cash payout under the program at the end of the performance period is calculated using the following formula: # PSUs X Payout % X Avg Q4 stock price of the final year of the performance period
Termination Rules		In the event of a termination following a change in control, all unvested PSUs vest immediately based on performance through the change in control. The shares do not automatically vest upon any other termination circumstance. In the event of retirement, death, disability, or a qualifying termination under the Basic Severance Plan, the number of PSUs is prorated based on termination date and paid based on actual performance at the end of the applicable performance period.


Participants		Officers of QEP, including the NEOs.
Strike Price		The strike price is the price at which the holder of the stock option may purchase a share of common stock and is equal to the closing price on the date of grant.
Vesting		The vesting schedule of the grants extends over a three-year period, with one-third of the shares vesting each year, a feature that encourages retention.
Term		Stock options expire seven years from the date of grant.
Number of Options		The number of options is determined using the closing price on the grant date and a stock option compensation value determined using the Black-Scholes-Merton method.
Termination Rules		In the event of a change in control, death or disability or in the case of all NEOs except Mr. Stanley, a qualifying termination under the Basic Severance Plan, all unvested options vest immediately. Unvested options are forfeited upon any other termination circumstance.
Other		Backdating, discounting or repricing of stock options is not permitted.


Participants		Employees selected by QEP’s compensation committee, including the NEOs.
Vesting		The vesting schedule of the grants extends over a three-year period, with one-third of the shares vesting each year, a feature that encourages retention.
Number of Shares		The number of shares is determined using the closing price on the grant date.
Dividends		Dividends are paid on unvested (restricted) shares.
Termination Rules		In the event of a change in control, death or disability or in the case of all NEOs except Mr. Stanley, a qualifying termination under QEP’s Basic Severance plan, all unvested shares vest immediately. Unvested shares are forfeited upon any other termination circumstance.


Participants		The initial participants in this program were recommended by the Compensation Committee and approved by the board of directors of the QEPM General Partner based on their direct contribution to the IPO of QEPM. In the future, participants will be employees who directly support our midstream business, as selected by the Compensation Committee and approved by the QEPM Board.
Vesting		The vesting schedule of the grants extends over a three-year period, with one-third of the shares vesting each year, a feature that encourages retention.
Number of Units		The number of units is determined by dividing the target dollar amount to be issued as phantom units by the closing price per share of QEPM common units on the grant date.
Dividends		QEPM distributions are paid on unvested phantom units.
Termination Rules		In the event of a change in control of QEPM or QEP, death or disability, all unvested units vest immediately. Unvested units are forfeited upon any other termination circumstance.


Name of Beneficial Owners	Number of Shares Beneficially Owned	Percentage of Class
Blackrock, Inc.⁽¹⁾
40 East 52^nd Street
New York, NY 10022
JANA Partners, LLC⁽²⁾
767 5^th Avenue
New York, NY 10153
JPMorgan Chase & Co.⁽³⁾.
270 Park Ave.
New York, NY 10017
The Vanguard Group⁽⁴⁾
100 Vanguard Boulevard
Malvern, PA 19355
All executive officers and directors as a group ( persons)


	Page
Unaudited Pro Forma Combined Financial Statements
Introduction		F-2
Unaudited Pro Forma Combined Statement of Operations for the Three Months Ended March 31, 2014		F-3
Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2013		F-4
Unaudited Pro Forma Combined Balance Sheet as of March 31, 2014		F-5
Notes to the Unaudited Pro Forma Combined Financial Statements		F-6

QEP Field Services Company Combined Financial Statements
Report of Independent Registered Public Accounting Firm		F-8
Combined Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011		F-9
Combined Balance Sheets as of December 31, 2013 and 2012		F-10
Combined Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011		F-11
Combined Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011		F-12
Notes Accompanying the Combined Financial Statements		F-13

QEP Field Services Company Unaudited Combined Financial Statements
Unaudited Combined Statements of Operations for the Three Months Ended March 31, 2014 and 2013		F-26
Unaudited Combined Balance Sheets as of March 31, 2014 and December 31, 2013		F-27
Unaudited Combined Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013		F-28
Unaudited Combined Statements of Equity for the Three Months Ended March 31, 2014 and 2013		F-29
Notes Accompanying the Unaudited Combined Financial Statements		F-30


	QEPFS Historical			QEPFS Retained			Pro Forma Adjustments			Pro Forma
	(in millions, except per share amounts)
REVENUE
NGL sales	$	33.1		$	—		$	—		$	33.1
Processing (fee-based) revenue		16.9			—			—			16.9
Other processing revenue		8.1			—			—			8.1
Gathering revenue		33.2			(5.0	)(a)		—			28.2
Other gathering revenue		11.2			—			—			11.2
Purchased gas and NGL sales		0.8			—			—			0.8

Total Revenue		103.3			(5.0	)		—			98.3

OPERATING EXPENSES
Purchased gas and NGL sales		0.3			—			—			0.3
Processing expense		4.6			—			—			4.6
Processing plant fuel and shrinkage		10.8			—			—			10.8
Gathering expense		10.0			(1.2	)(a)		—			8.8
NGL transportation and fractionation costs		5.5			—			—			5.5
General and administrative		14.5			(1.4	)(a)		—			13.1
Taxes other than income taxes		1.8			(0.4	)(a)		—			1.4
Depreciation and amortization		16.5			(2.2	)(a)		—			14.3

Total Operating Expenses		64.0			(5.2	)		—			58.8
Net loss from property sales		—			—			—			—

OPERATING INCOME		39.3			0.2			—			39.5
Income from unconsolidated affiliates		2.2			—			—			2.2
Interest expense, net		(0.6	)		—			(0.9	)(d)
									(e)

INCOME BEFORE INCOME TAXES		40.9			0.2			(0.9	)
Income taxes		(12.8	)		(0.1	)(a)		0.3	(k)

NET INCOME		28.1			0.1			(0.6	)
Net income attributable to noncontrolling interest		(5.7	)		—			(2.3	)(c)

NET INCOME ATTRIBUTABLE TO US	$	22.4		$	0.1		$	(2.9	)

Pro forma earnings per share
Basic												(j)
Diluted												(j)
Pro forma shares outstanding
Basic												(j)
Diluted												(j)


	QEPFS Historical			QEPFS Retained			Pro Forma Adjustments			Pro Forma
	(in millions, except per share amounts)
REVENUE
NGL sales	$	105.2		$	—		$	—		$	105.2
Processing (fee-based) revenue		74.0			—			—			74.0
Other processing revenue		13.2			—			—			13.2
Gathering revenue		152.2			(28.1	)(a)		—			124.1
Other gathering revenue		50.5			—			—			50.5
Purchased gas and NGL sales		8.6			—			—			8.6

Total Revenue		403.7			(28.1	)		—			375.6

OPERATING EXPENSES
Purchased gas and NGL sales		9.0			—			—			9.0
Processing expense		16.1			—			—			16.1
Processing plant fuel and shrinkage		32.2			—			—			32.2
Gathering expense		39.7			(6.4	)(a)		—			33.3
NGL transportation and fractionation costs		16.3			—			—			16.3
General and administrative		47.5			(4.9	)(a)		—			42.6
Taxes other than income taxes		6.6			(1.4	)(a)		—			5.2
Depreciation and amortization		63.8			(8.6	)(a)		—			55.2

Total Operating Expenses		231.2			(21.3	)		—			209.9
Net loss from property sales		(0.5	)		—			—			(0.5	)

OPERATING INCOME		172.0			(6.8	)		—			165.2
Interest and other income		1.2			—			—			1.2
Income from unconsolidated affiliates		6.1			—			—			6.1
Interest expense, net		(3.1	)		3.7	(a)		(6.7	)(d)
									(e)

INCOME BEFORE INCOME TAXES		176.2			(3.1	)		(6.7	)
Income taxes		(59.2	)		1.7	(a)		2.4	(k)

NET INCOME		117.0			(1.4	)		(4.3	)
Net income attributable to noncontrolling interest		(12.0	)		—			(12.6	)(b)
								(7.6	)(c)

NET INCOME ATTRIBUTABLE TO US	$	105.0			(1.4	)	$	(24.5	)

Pro forma earnings per share
Basic												(j)
Diluted												(j)
Pro forma shares outstanding
Basic												(j)
Diluted												(j)


	QEPFS Historical		QEPFS Retained			Pro Forma Adjustments			Pro Forma
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	20.2	$	—				(f)
								(g)
								(h)
Accounts receivable, net		96.3		(0.1	)(a)		34.3	(l)
Accounts receivable from related party		39.7		(5.4	)(a)		(34.3	)(l)
Income taxes receivable		16.5		(3.2	)(a)		0.3	(k)
Natural gas imbalance receivable		14.6		(0.8	)(a)		—			13.8
Inventory, at lower of average cost or market		8.0		—			—			8.0
Deferred income taxes current		2.7		—				(k)
Other current assets		3.2		(0.2	)(a)		—			3.0

Total current assets		201.2		(9.7	)		0.3

Property, plant and equipment, net		1,294.2		(168.0	)(a)		—			1,126.2
Investment in unconsolidated affiliates		38.5		—			—			38.5
Other noncurrent assets		3.2		—				(h)

Total assets	$	1,537.1	$	(177.7	)	$	0.3

LIABILITIES
Current liabilities:
Accounts payable	$	86.3	$	(2.1	)(a)	$	15.9	(l)
Accounts payable from related party		17.5		(1.6	)(a)		(15.9	)(l)
Deferred revenue		11.0		—			—			11.0
Natural gas imbalance liability		14.6		(0.8	)(a)		—			13.8
Accrued compensation		2.6		(0.4	)(a)		—			2.2
Other current liabilities		1.2		—	(a)		—			1.2

Total current liabilities		133.2		(4.9	)		—

Long-term debt		—		—			230.0	(c)
								(f)
Deferred income taxes		244.1		(52.8	)(a)			(k)
Asset retirement obligation		33.0		(4.0	)(a)		—			29.0
Deferred revenue		12.5		—			—			12.5
EQUITY
Common stock				—				(i)

Net investment		615.9		(116.0	)(a)		(276.4	)(c)
							0.3	(k)
								(g)
								(i)
Noncontrolling interest		498.4		—			46.4	(c)

Total equity		1,114.3		(116.0	)		(229.7	)

Total liabilities and equity	$	1,537.1	$	(177.7	)	$	0.3


	December 31, 2013		December 31, 2012
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	18.1	$	—
Accounts receivable, net		61.2		54.4
Accounts receivable from related party		28.4		33.3
Income taxes receivable		29.2		—
Natural gas imbalance receivable		8.2		3.9
Inventory, at lower of average cost or market		5.1		14.6
Deferred income taxes—current		2.7		2.6
Other current assets		1.5		0.3

Total current assets		154.4		109.1

Property, plant and equipment, net		1,287.0		1,269.6
Investment in unconsolidated affiliates		39.0		40.7
Other noncurrent assets		4.7		5.1

Total assets	$	1,485.1	$	1,424.5

LIABILITIES
Current liabilities:
Checks outstanding in excess of cash balances	$	—	$	1.7
Accounts payable		32.8		24.3
Accounts payable to related party		46.7		18.6
Income taxes payable		—		14.9
Deferred revenue		9.6		—
Natural gas imbalance liability		8.2		3.9
Accrued compensation		4.7		5.9
Other current liabilities		1.9		—

Total current liabilities		103.9		69.3

Long-term debt to related party		—		199.5
Deferred income taxes		241.9		328.2
Asset retirement obligation		32.4		27.1
Deferred revenue		12.9		10.3
Commitments and contingencies (see Note 10)
EQUITY
Owners’ net investment		593.8		742.4
Noncontrolling interest		500.2		47.7

Total net equity		1,094.0		790.1

Total liabilities and equity	$	1,485.1	$	1,424.5


	Owners’ Net Investment			Noncontrolling Interest			Total Net Equity
	(in millions)
Balance at December 31, 2010	$	455.5		$	52.8		$	508.3
Net income		147.3			3.2			150.5
Contribution from parent, net		13.3			—			13.3
Distribution of noncontrolling interest		—			(5.4	)		(5.4	)
Change in unrealized fair value of derivatives, net of tax		(0.5	)		—			(0.5	)

Balance at December 31, 2011	$	615.6		$	50.6		$	666.2

Net income		133.1			3.7			136.8
Distribution to parent, net		(6.8	)		—			(6.8	)
Distribution of noncontrolling interest		—			(6.6	)		(6.6	)
Reclassification of previously deferred derivative gains in OCI, net of tax		0.5			—			0.5

Balance at December 31, 2012	$	742.4		$	47.7		$	790.1

Net income		105.0			12.0			117.0
Distributions to parent, net		(16.0	)		—			(16.0	)
Distribution of noncontrolling interest		—			(6.3	)		(6.3	)
Dividend to QEP		(238.0	)		—			(238.0	)
Net proceeds from initial public offering		—			449.6			449.6
Distribution to unitholders		—			(3.0	)		(3.0	)
Equity-based compensation		0.4			0.2			0.6

Balance at December 31, 2013	$	593.8		$	500.2		$	1,094.0


Total proceeds from the IPO	$	483.0
IPO costs		(33.4	)

Net proceeds from the IPO		449.6
QEPM revolving credit facility origination fees		(3.0	)
QEPM repayment of outstanding debt with QEP		(95.5	)

Net proceeds distributed to QEP from the Offering	$	351.1


	Estimated useful lives	At December 31,
		2013			2012
		(in millions)
Gathering and processing equipment	5 to 40 years	$	1,675.3		$	1,604.9
General support equipment	3 to 30 years		21.4			22.0

Total property, plant and equipment			1,696.7			1,626.9
Accumulated depreciation			(409.7	)		(357.3	)

Total net property, plant and equipment		$	1,287.0		$	1,269.6


	Asset Retirement Obligations
	2013
	(in millions)
ARO liability at January 1,	$	27.1
Accretion		2.1
Liabilities incurred		2.2
Revisions		1.1
Liabilities settled		(0.1	)

ARO liability at December 31,	$	32.4


	Year Ended December 31,
*Derivative instruments not designated as cash flow hedges*	2013		2012		2011
*Realized gains on commodity derivative contracts*	(in millions)
NGL derivative contracts	$	—	$	8.4	$	—