10-K 1 midstream10-k2013.htm 10-K Midstream 10-K 2013


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
 
001-36047
 
 
(Commission File No.)
 
QEP MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
 
STATE OF DELAWARE
 
80-0918184
(State or other jurisdiction of incorporation)
 
(I.R.S. Employer Identification No.)
 1050 17th Street, Suite 500, Denver, Colorado 80265
(Address of principal executive offices)
Registrant's telephone number, including area code: 303-672-6900
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partnership Interests
 
New York Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨     No   ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
o
 
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
ý
(Do not check if a smaller reporting company)
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
 



At February 28, 2014, there were 26,710,748 common units, 26,705,000 subordinated units and 1,090,117 general partner units outstanding. QEP Midstream Partners LP completed its initial public offering on August 14, 2013.



QEP Midstream Partners, LP
Form 10-K for the Year Ended December 31, 2013

TABLE OF CONTENTS
 

 
Page
 



1


Explanatory Note

Certain information in this report includes periods prior to the completion of QEP Midstream Partners, LP's initial public offering (the IPO) and prior to the effective dates of the agreements related to the IPO that are discussed herein. Consequently, the consolidated financial statements and related discussion of financial condition and results of operations contained in this report include periods that pertain to QEP Midstream Partners, LP Predecessor, our Predecessor for accounting purposes. Because the results of our Predecessor include results for both the properties conveyed to us in connection with the IPO and properties retained by our Predecessor, we do not consider the results of our Predecessor to be indicative of our future results.

Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (periods prior to the IPO on August 14, 2013), refer to QEP Midstream Partners, LP Predecessor. References in this report to "QEP Midstream," the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after the IPO in the present tense or prospectively, refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of this report, "QEP" refers to QEP Resources, Inc. (NYSE: QEP) and its consolidated subsidiaries.



2


Where You Can Find More Information

QEP Midstream Partners, LP (QEP Midstream or the Partnership) files annual, quarterly, and current reports with the Securities and Exchange Commission (SEC). Further, the Partnership filed a registration statement on Form S-1 with the SEC in 2013 regarding the Partnership's initial public offering that occurred on August 14, 2013. QEP files annual, quarterly and current reports with the SEC, which include, on a consolidated basis, financial information about QEP Midstream. QEP Midstream also regularly files other documents with the SEC. These reports and other information can be read and copied at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549-0213. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC also maintains an Internet site at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including QEP Midstream.

Investors can also access financial and other information via QEP Midstream's website at www.qepm.com. QEP Midstream makes available, free of charge through the website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to such reports, and all reports filed by executive officers and directors under Section 16 of the Exchange Act reporting transactions in QEP Midstream securities. Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC. Information contained on or connected to QEP Midstream's website which is not directly incorporated by reference into the Partnership's Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

QEP Midstream's website, www.qepm.com, also contains copies of charters for the Audit and Conflict Committees, along with QEP Midstream's Corporate Governance Guidelines, Code of Business Conduct and Ethics, Insider Trading Policy, and Whistleblower Policy.

Finally, you may request a copy of filings other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing or calling QEP Midstream, 1050 17th Street, Suite 500, Denver, CO 80265 (telephone number: 1-303-672-6900).

Forward-Looking Statements

This Annual Report on Form 10-K contains or incorporates by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:

•
belief that the historical financial results of our Predecessor are not indicative of our future results;
•
organic growth from our existing assets;
•
competitive advantage in attracting additional third-party volumes on our systems;
•
our financial flexibility and strong capital structure;
•
fees charged for firm service;
•
benefits provided by our relationship with QEP;
•
competition from other pipelines;
•
seasonality of our business;
•
adequacy of our insurance;
•
our compliance with governmental regulations and the impacts of compliance and noncompliance with governmental regulations on our business, financial position, results of operations and cash flows;
•
impacts of climate change;
•
impacts of a cyber-attack on our operations and those of our customers;
•
estimated amounts and allocation of capital expenditures;
•
use of alternative financing strategies such as joint venture arrangements;
•
factors affecting the comparability of our operating results;
•
variances between the allocation of taxable income to our partners and net income reported in our financial statements;
•
changes to the amount and time that the executives of our general partner dedicate to our business;
•
reasonableness of the methodologies for allocating general and administrative costs of our Predecessor;
•
estimates of contingency losses and outcome of pending litigation and other legal proceedings;
•
drilling activity on dedicated acreage and its impact on throughput levels and production;

3


•
correlation of drilling activity with commodity prices and production levels;
•
our ability to maximize operating profits by minimizing operating and maintenance costs;
•
stability of operating and maintenance costs across broad ranges of throughput volumes;
•
fluctuation of operating and maintenance costs from period to period;
•
anticipated general and administrative expenses;
•
the significance of Adjusted EBITDA and distributable cash flow as performance measures;
•
trends impacting our business;
•
anticipated levels of exploration and production activities in the areas we operate;
•
impact of oil and natural gas prices on production rates;
•
decline in production from the various properties dedicated to our gathering systems;
•
impact of inflation and our ability to recover higher operating costs from our customers;
•
impact of interest rates on our unit price, cost of capital and ability to raise funds, expand operations or make future acquisitions;
•
impact of regulations on our compliance costs, the time to obtain required permits and throughput in our gathering systems;
•
acquisition of additional midstream assets from QEP Field Services Company and third parties;
•
impact of changes to the funding of affiliated and third party transactions on the comparability of our cash flow statements, working capital analysis and liquidity discussion;
•
future cash distributions;
•
variance of expansion capital expenditures from period to period;
•
funding for acquisition and expansion capital expenditures during 2014;
•
maintenance of separate accounts and utilization of QEP's cash management system and expertise;
•
sources of liquidity;
•
sufficiency of cash generated from operations, borrowings under our revolving credit facility and issuance of additional debt and equity securities to satisfy short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions;
•
exposure to credit risk resulting from the concentration of our customers;
•
impact of QEP's and Questar Gas Corporation's, as our largest customers, failure to perform under the terms of our gathering agreements;
•
impact of QEP's failure to perform under the terms of the Omnibus Agreement (defined below);
•
adequacy of our credit review procedures, loss reserves, customer deposits and collection procedures;
•
usefulness of historical data related only to properties conveyed to us in connection with the IPO;
•
supplemental disclosures regarding properties conveyed to us in the IPO; and
•
utilization of risk management tools to minimize future commodity price risks.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks or uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:

•
the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10-K;
•
outcome of QEP's efforts to separate its midstream business;
•
changes in general economic conditions;
•
competitive conditions in our industry;
•
actions taken by third-party operators, processors and transporters;
•
the demand for oil and natural gas storage and transportation services;
•
our ability to successfully implement our business plan;
•
our ability to complete internal growth projects on time and on budget;
•
the price and availability of debt and equity financing;
•
the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;
•
competition from the same and alternative energy sources;
•
energy efficiency and technology trends;
•
operating risks and hazards incidental to transporting, storing and processing oil and natural gas, as applicable;
•
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•
production trends in our areas of operations;
•
interest rates;

4


•
labor relations;
•
large customer defaults;
•
change in availability and cost of capital;
•
changes in tax status;
•
the effect of existing and future laws and government regulations; and
•
the effects of future litigation.

QEP Midstream undertakes no obligation to publicly correct or update the forward-looking statements in this Annual Report on Form 10-K, in other documents, or on the website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

5


Glossary of Terms

Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure. Management defines Adjusted EBITDA as net income attributable to the Partnership or the Predecessor before depreciation and amortization, interest and other income, interest expense, gains and losses from asset sales, deferred revenue associated with minimum volume commitment payments, and certain other non-cash and/or non-recurring items.

B Billion.

barrel    One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

BBls/d    Barrels per day.

bhp Brake horsepower — the actual or useful horsepower of an engine, usually determined from the force exerted on a friction brake or dynamometer connected to the drive shaft.

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).

cfe Cubic foot or feet of natural gas equivalents.

crude oil    A mixture of hydrocarbons that exists in liquid phase in underground reservoirs.

Distributable Cash Flow Management defines Distributable Cash Flow as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity method investments and non-controlling interests, and other non-cash expenses.

EIA    United States Energy Information Administration.

end user    The ultimate user and consumer of transported energy products.

FERC    Federal Energy Regulatory Commission.

GAAP Accounting principles generally accepted in the United States of America.

gas All references to "gas" in this report refer to natural gas.

LIBOR London Interbank Offered Rate ("LIBOR") is the interest rate that banks charge each other for one-month, three-month, six-month and one-year loans.

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

MBbls    One thousand barrels.

MBbls/d    One thousand barrels per day.

MMBtu    One million Btu.

MMBtu/d One million Btu per day.

MMcf    One million cf.

MMCf/d One million cf per day.

NGL    Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.


6


NYSE New York Stock Exchange.

oil All references to "oil" in this report refer to crude oil.    

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.

T Trillion.

throughput    The volume of crude oil, natural gas, or hydrocarbon-based products transported or passing through a pipeline, plant, terminal or other facility during a particular period.


7


FORM 10-K
ANNUAL REPORT 2013
PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Overview

We are a master limited partnership formed by QEP to own, operate, acquire and develop midstream energy assets. Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota. As of the year ended December 31, 2013, our gathering systems had 1,512 miles of pipeline. We believe our customers are some of the largest natural gas producers in the Rocky Mountain region.

We provide all of our gathering services through fee-based agreements, the majority of which have annual inflation adjustment mechanisms. As of December 31, 2013, approximately 81% of our revenues are generated pursuant to contracts with remaining terms in excess of five years, including 59% of our revenues that are generated pursuant to “life-of-reserves” contracts. In addition to our fee-based gathering services, we generate approximately 4% of our revenue through the sale of condensate volumes that we collect on our gathering systems, which were sold at a fixed price of $85.25. For the period August 14, 2013 to December 31, 2013 (the Post-IPO Period) , approximately 68% of our revenue came from QEP, making QEP our largest customer.

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

We believe that one of our strengths is our relationship with QEP. QEP is engaged in crude oil and natural gas exploration and production (E&P) activities, as well as midstream activities related to its E&P operations. For the year ended December 31, 2013, QEP reported 4.1 Tcfe of total proved reserves and total production of 309.0 Bcfe, representing a 3% increase and a 3% decrease, respectively, in proved reserves and production as compared to the year ended December 31, 2012. We believe this relationship will provide us with the opportunity to increase throughput volumes from QEP production in areas where we have gathering systems.

In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate the Company’s midstream business, including the ownership and control of QEP Field Services, which include its general and limited partner interests in QEP Midstream. We believe there is nothing in QEP’s announced strategy to separate its midstream business that precludes QEP Field Services from offering us acquisition opportunities to purchase additional midstream assets from it or to jointly pursue midstream acquisitions with it prior to or subsequent to the separation. Further, we do not believe QEP’s acreage dedicated to our assets will be changed significantly due to the separation and we believe these acreage dedications will continue to provide us a platform for future organic growth from our existing assets.

2013 Financial and Operating Highlights

Financial and operating highlights for the Post-IPO Period include:
•
Generated $48.1 million of revenue, $19.1 million of net income, $30.7 million of Adjusted EBITDA and $26.7 million of Distributable Cash Flow (Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures that are reconciled in Item 6 of Part II of this Annual Report on Form 10-K);
•
Announced a third quarter 2013 distribution of $0.13 (pro-rated for the Post-IPO Period) and a fourth quarter 2013 distribution of $0.26 per unit; and
•
Had average gross throughput of 1.7 million MMBtu/d of natural gas, 12,452 Bbls/d of crude oil and 12,609 Bbls/d of water, and sold 23.4 Mbbls of condensate.


8


Organizational Structure

The following table and diagram illustrate our ownership and organizational structure as of December 31, 2013:
 
Ownership
Interest
Common units held by the public
42.2
%
Common units held by QEP
6.8
%
Subordinated units held by QEP
49.0
%
Long-Term Incentive Plan (LTIP) common units
*

General partner units
2.0
%
Total
100.0
%



*Represents less than 1% of the outstanding units.


9


Initial Public Offering

On August 14, 2013, the Partnership completed its IPO selling 20,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $21.00 per common unit. The Partnership 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 $29.3 million. In addition, as of September 4, 2013, the underwriters exercised their 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 the Partnership (refer to "Note 3 - Initial Public Offering" in Item 8 of Part II of this Annual Report on Form 10-K).

As part of the IPO, QEP Midstream Partners GP, LLC (General Partner) and QEP Field Services Company (QEP Field Services), both QEP subsidiaries, collectively contributed to the Partnership (i) a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the Operating Company), QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C. (Rendezvous Pipeline), (ii) a 78% interest in Rendezvous Gas Services, L.L.C. (Rendezvous Gas), and (iii) a 50% equity interest in Three Rivers Gathering, L.L.C. (Three Rivers Gathering). The General Partner serves as general partner of the Partnership and, together with QEP, provides services to the Partnership pursuant to an Omnibus Agreement (the Omnibus Agreement) between the parties. In addition, on August 14, 2013, in connection with the closing of the IPO, the Agreement of Limited Partnership was amended and restated by the First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (as amended and restated, the Partnership Agreement).

Business Strategies

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

•
Pursuing acquisitions from QEP Field Services. We intend to seek opportunities to expand our operations primarily through acquisitions from QEP Field Services, which may include the following:
◦
QEP Field Services’ portfolio of midstream assets, which include gathering, processing, and treating assets; and
◦
Expansion projects that QEP Field Services undertakes in the future as it builds additional midstream assets in support of QEP's E&P operations.
While we will review acquisition opportunities from third parties as they become available, we expect that most of our significant opportunities over the next several years will be sourced from QEP Field Services. Based on QEP Field Services' significant ownership interest in us, we believe QEP Field Services will offer us the opportunity to purchase additional midstream assets from it, as well as to jointly pursue midstream acquisitions with it. QEP Field Services is under no obligation, however, to offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any such additional assets or to pursue any such joint acquisitions. We are currently not a party to any written agreements to purchase additional midstream assets from QEP Field Services. For a description of QEP Field Services’ retained midstream asset portfolio, refer to "Our Relationship with QEP Resources, Inc.”

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

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

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

•
Maintaining our financial flexibility. We expect to maintain a capital structure using appropriate amounts of debt and equity financing. We believe that our revolving credit facility, our ability to issue additional partnership units and long-

10


term debt, and our relationship with QEP and our existing joint venture partners will provide us with the financial flexibility to execute of our business strategy.

•
Minimizing direct commodity price exposure. We intend to maintain our focus on providing midstream services under fee-based agreements. As of the time of the IPO, we entered into a fixed price condensate purchase agreement with QEP to remove price exposure associated with our condensate sales. We intend to continue to limit our direct exposure to commodity price risk and to promote cash flow stability by utilizing fee-based contracts and fixed-price crude oil and condensate sales agreements. In addition, we may utilize risk management tools to minimize future commodity price risk associated with any assets we acquire or contracts we enter into in the future.

Competitive Strengths

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

•
Our affiliation with QEP. As the owner of our General Partner, all of our IDRs, and a 55.8% limited partner interest in us, we believe QEP Field Services is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.
◦
Acquisition opportunities. As of December 31, 2013, QEP Field Services owns a substantial and growing portfolio of midstream assets, and we believe QEP Field Services will offer us the opportunity to purchase some or all of those midstream assets in the future, although it is not obligated to do so.
◦
QEP. QEP is actively operating in the Rocky Mountain region and as of December 31, 2013, served as the operator for 4.1 Tcfe of total proved reserves, a portion of which is dedicated to our gathering systems. QEP is our largest customer and is an anchor shipper on a number of our gathering systems.
◦
Acreage Dedication. As of December 31, 2013, QEP had dedicated approximately 193,000 gross acres to our existing systems, which we believe contain significant oil and natural gas reserves. We believe that drilling activity on acreage that QEP has dedicated to us will increase the gathering and transmission volumes on our systems.

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

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

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

•
Financial flexibility and strong capital structure. As of December 31, 2013, we had no debt outstanding and a borrowing capacity of $500.0 million under our revolving credit facility. We believe that our borrowing capacity and our ability to access debt and equity capital markets will provide us with the financial flexibility necessary to achieve our business strategy.

Industry Overview

General

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


11


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

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


Refined petroleum products, such as jet fuel, gasoline and distillate fuel oil, are all sources of energy derived from crude oil. According to the most recent EIA report on energy statistics issued in January 2014, petroleum accounted for about 36% of the nation’s total annual energy consumption during 2012. The diagram below depicts the segments of the crude oil value chain:



Natural Gas Midstream Services

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

12



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 to 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 to be 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 transported to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to provide 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. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing.    The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to remove these heavier hydrocarbon components, as well as natural gas condensate. NGLs not only interfere with pipeline transportation, but are also valuable commodities once removed from the natural gas stream. The removal and separation of NGLs usually takes place in a processing plant using industrial processes that exploit differences in the weights, boiling points, vapor pressures and other physical characteristics of NGL components.

Fractionation.    The mixture of NGLs that results from natural gas processing is generally comprised of the following five components: ethane, propane, normal butane, iso-butane and natural gasoline. 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 (LDCs). LDCs purchase natural gas on interstate and intrastate pipelines and market that natural gas to commercial, industrial and residential end users. Transmission pipelines generally span considerable distances and consist of large-diameter pipelines that operate at higher pressures than gathering pipelines to facilitate the transportation of greater quantities of natural gas. The concentration of natural gas production in a few regions of the U.S. generally requires transmission pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions, including the FERC. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

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


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Crude Oil Gathering and Transportation

Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the U.S. Crude oil pipelines transport oil from the wellhead to logistics hubs and/or refineries. Common carrier pipelines have published tariffs that are regulated by the 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 transportation 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.

Contractual Arrangements

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

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

Processing Contracts

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

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

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

Common Contractual Provisions

Level of Service Provision

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

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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 these 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, firm service customers enjoy the first right to capacity on the system or at the processing facility up to the reserved amount. Firm service is usually contracted for by customers who need a high degree of certainty that their product will move on the system or at a processing facility even when total volumes 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 processed. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the processing facility.

Dedication Provisions

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

Our Relationship with QEP Resources, Inc.

One of our strengths is our relationship with QEP. QEP is a holding company with three major lines of business — natural gas and oil exploration and production, midstream field services, and energy marketing — which are conducted through three principal subsidiaries:
•
QEP Energy Company acquires, explores for, develops and produces natural gas, crude oil and NGL;
•
QEP Field Services provides midstream field services, including the gathering of natural gas, oil, and water, gas processing, compression and treating services for affiliates and third parties; and
•
QEP Marketing Company markets QEP Energy's and third-party natural gas and crude oil, and owns and operates an underground natural gas storage reservoir.

QEP is actively operating in several natural gas and crude oil basins in the United States. QEP had approximately 1.6 million total net leasehold acres as of December 31, 2013, of which approximately 0.9 million net acres were located in Colorado, North Dakota, Utah and Wyoming. For the year ended December 31, 2013, QEP reported 4.1 Tcfe of total proved reserves and total production of 309.0 Bcfe, representing a 3% increase and a 3% decrease, respectively, in proved reserves and production as compared to the year ended December 31, 2012.

The following tables provide information regarding QEP Field Services’ midstream assets as of December 31, 2013.

Gathering
Gathering System
 
Primary
Location
 
Length
(miles)
 
Receipt
Points
 
Compression
(bhp)
 
Throughput
Capacity
(MMcf/d)
 
Average Daily
Throughput
(Thousand
MMBtu/d)(1)
Uinta Basin Gathering System
 
Uinta Basin
 
610

 
1,954

 
54,306

 
299

 
201

Uintah Basin Field Services(2)
 
Uinta Basin
 
100

 
21

 
5,360

 
26

 
11

Haynesville Gathering System
 
Haynesville Shale
 
200

 
230

 
4,472

 
2,000

 
184

Total
 
 
 
910

 
2,205

 
64,138

 
2,325

 
396

            
(1) 
Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2013.
(2) 
QEP Field Services’ ownership in Uintah Basin Field Services is 38%.

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Processing/Treating/Fractionation
Asset
 
Primary Location
 
Asset Type
 
Facility Type
 
Throughput
Capacity
(MMcf/d)(1)
 
Average Daily
Throughput
(Thousand
MMBtu/d)(1)
Blacks Fork Processing Complex
 
Green River Basin
 
Processing
 
Cryogenic /
Joule-Thomson
 
835

 
 
477

 
 
 
 
 
Fractionation
 
Fractionator
 
15,000

(2) 
 
2,414

(2) 
Emigrant Trail Processing Plant
 
Green River Basin
 
Processing
 
Cryogenic
 
55

 
 
54

 
Vermillion Processing Plant(3)
 
Southern Green River Basin
 
Processing
 
Cryogenic
 
43

 
 
51

 
Uinta Basin Processing Complex
 
Uinta Basin
 
Processing
 
Cryogenic /
Refrigeration
 
650

 
 
278

 
Haynesville Gathering System
 
Haynesville Shale
 
Treating
 
Treating
 
600

 
 
184

 
Total
 
 
 
 
 
Processing
 
1,583

 
 
 
 
 
 
 
 
 
 
Treating
 
600

 
 
 
 
 
 
 
 
 
 
Fractionation
 
15,000

(2) 
 
 
 
            
(1) 
Represents 100% of the inlet capacity and inlet throughput of the assets as of and for the year ended December 31, 2013.
(2) 
Throughput measured in barrels of NGL per day.
(3) 
QEP Field Services’ ownership in the Vermillion Processing Plant is 71%.

As the owner of (i) our 2.0% general partner interest, (ii) all of our incentive distribution rights, and (iii) a 55.8% limited partner interest in us, we believe that QEP Field Services is motivated to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business. In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate its midstream business, including the ownership and control of QEP Field Services, which includes its general and limited partner interests in QEP Midstream. We believe there is nothing in QEP’s announced strategy to separate its midstream business that precludes QEP Field Services from offering us acquisition opportunities to purchase additional midstream assets from it or to jointly pursue midstream acquisitions with it before or after the separation. However, QEP Field Services is under no obligation to make acquisition opportunities available to us, is not restricted from competing with us and may acquire, construct or dispose of midstream assets without any obligation to offer us the opportunity to purchase or construct these assets. Further, we do not believe QEP’s acreage dedicated to our assets will be changed significantly due to the separation and we believe these acreage dedications will continue to provide us with a platform for future organic growth from our existing assets. Refer to Note 4 - Related Party Transactions, in Item 8 of Part II of this Annual Report on Form 10-K.

We entered into an Omnibus Agreement with QEP in connection with the IPO. The Omnibus Agreement addresses our payment of fees to QEP Field Services for certain general and administrative services and QEP’s and QEP Field Services' indemnification of us for certain matters, including environmental, contractual, title and tax matters. While not the result of arm’s-length negotiations, we believe the terms of the Omnibus Agreement with QEP are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Refer to Note 4 - Related Party Transactions, in Item 8 of Part II of this Annual Report on Form 10-K.

While our relationship with QEP and its subsidiaries is a strength, it is also a source of potential conflicts. Refer to Item 1A of Part I of this Annual Report on Form 10-K for additional information. Additionally, we have no control over QEP’s business decisions and operations, and QEP is under no obligation to adopt a business strategy that favors us.


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Our Assets and Operations

Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines. The following table provides information regarding our assets by system as of and for the year ended December 31, 2013:
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

 
  
 
566

 
  
 
 
Oil/Condensate Gathering
 
56

 
103

 
—

 
7,137

 
(2) 
 
3,728

 
(2) 
 
 
Water Gathering
 
88

 
103

 
—

 
21,990

 
(2) 
 
11,549

 
(2) 
 
 
Oil/Condensate Transmission(3)
 
61

 
12

 
—

 
40,800

 
(2) 
 
10,566

 
(2) 
Rendezvous Gas (4)
 
Gas Gathering
 
310

 
3

 
7,800

 
1,032

 
   
 
643

 
   
Rendezvous Pipeline (3)
 
Gas Transmission
 
21

 
1

 
—

 
460

 
   
 
350

 
   
Vermillion Gathering System
 
Gas Gathering
 
517

 
505

 
23,932

 
212

 
   
 
126

 
   
Three Rivers Gathering System (5)
 
Gas Gathering
 
52

 
8

 
4,735

 
212

 
   
 
107

 
   
Williston Gathering System
 
Gas Gathering
 
17

 
34

 
239

 
3

 
   
 
2

 
   
 
 
Oil Gathering
 
17

 
34

 
—

 
7,000

 
(2) 
 
3,084

 
(2) 
Total
 
 
 
1,512

 
1,120

 
77,759

 
 
 
 
 
 
 
 
            
(1) 
Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2013.
(2) 
Capacity and throughput measured in Bbls/d.
(3) 
FERC-regulated pipeline.
(4) 
Our ownership interest in Rendezvous Gas is 78%.
(5) 
Our ownership interest in Three Rivers Gathering is 50%.

Green River System

Our Green River System, located in western Wyoming, consists of three integrated assets – the Green River Gathering Assets, the assets owned by Rendezvous Gas and the 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.

Green River Gathering Assets

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, Questar Gas Company (QGC), and WGR Operating, LP.

Rendezvous Gas

Rendezvous Gas is a joint venture between QEP Midstream 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 QEP Midstream or Western Gas. Rendezvous Gas entered into separate agreements with QEP Midstream and Western Gas to gather the natural gas dedicated to each party from producers within an area of mutual interest.


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Rendezvous Pipeline

Rendezvous Pipeline provides gas transportation services from QEP Field Services’ Blacks Fork processing 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.

Vermillion Gathering System

The 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 we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. The primary customers on our Vermillion Gathering System include QGC, Wexpro Development Company (Wexpro), QEP and Chevron USA, Inc. (Chevron). For the year ended December 31, 2013, approximately 71% 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 System

Three Rivers Gathering is a joint venture between QEP Midstream and Ute Energy Midstream Holdings, LLC (Ute Energy), which was formed to transport natural gas gathered by Uintah Basin Field Services, L.L.C., an indirectly owned subsidiary in which QEP Field Services owns a 38% interest (Uintah Basin Field Services), and other third-party volumes to gas processing facilities owned by QEP and third parties. The Three Rivers Gathering System is primarily supported by long-term, fee-based gas gathering agreements with minimum volume commitments. The system has aggregate minimum volume commitments of 212 thousand MMBtu/d from three different producers through 2018. The primary customers on our Three Rivers Gathering System include EnerVest Ltd., XTO Energy, Inc. (XTO), Anadarko and QEP.

Williston Gathering System

The Williston Gathering System is a crude oil and natural gas gathering system located in the Williston Basin in McLean County, North Dakota. The Williston Gathering System is primarily supported by long-term, fee-based, crude oil and gas gathering agreements with minimum volume commitments. The system has aggregate minimum volume commitments of approximately 5,600 Bbls/d of crude oil and five thousand MMBtu/d of natural gas from one producer through 2026. QEP and Marathon Oil Company are currently the only customers on our Williston Gathering System.

Competition

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

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

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

Seasonality

Our operations are affected by seasonal weather conditions. For example, from approximately December through March of each year, QEP typically ceases completion activity on drilled wells in the Pinedale Field due to adverse weather conditions. As a result, we generally do not add throughput on our Green River System during this period, and existing levels of throughput typically decline as the wells connected to our Green River System experience natural production declines. Condensate sales, however, tend to increase slightly in the first quarter, as the colder ground causes more condensate to fall out of the gas stream in our gathering system. We expect the impact of such seasonality to diminish as we expand our existing assets or acquire additional assets.


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Insurance

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We share insurance coverage with QEP, for which we reimburse QEP pursuant to the terms of the Omnibus Agreement. Our property and casualty insurance program includes coverage for physical damage to our properties, third-party liability, sudden and accidental pollution, workers’ compensation, auto liability, and employers’ liability. The General Partner maintains director and officer liability insurance under a separate policy from QEP’s corporate director and officer liability insurance. We also maintain our own property, business interruption and pollution liability insurance policies separately from QEP and at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Partnership against liability or loss from all potential consequences and damages. All insurance coverage is in amounts which management believes are reasonable and appropriate. As we continue to grow, we will continue to evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.

Safety and Maintenance

Some of our natural gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to the Natural Gas Pipeline Safety Act of 1968 (NGPSA) and the Pipeline Safety Improvement Act of 2002 (PSIA) as reauthorized and amended by the PIPES Act of 2006 (Pipes Act). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas (HCAs). Our crude oil pipeline and certain of our crude gathering lines are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979 (HLPSA) which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and the Pipeline Safety Act of 1992 (PSA) added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act of 1996 (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:

•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a HCA;
•improve data collection, integration and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating actions.

Although many of our pipeline facilities fall within a class that is currently not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our Rendezvous Pipeline assets and our Green River and Williston gathering systems. In 2013, we incurred approximately $0.1 million to complete the testing required by existing Department of Transportation (DOT) regulations and their state counterparts. We currently estimate that we will incur less than $0.1 million in costs during 2014 related to DOT regulations. 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, if we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

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The 2011 Pipeline Safety Act reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. On August 13, 2012, PHMSA published a proposed rulemaking consistent with the signed act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $0.2 million per violation per day, with a maximum of $2.0 million for a related series of violations. The PHMSA recently issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule change does not affect our current pipelines. Future liquid pipeline expansions may be subject to this rule, but we do not believe compliance with the rule will have a material effect on our operations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities that are regulated by PHMSA to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending 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 comply 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 states 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 U.S. Environmental Protection Agency (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. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

We and the entities in which we own interests are also subject to:
•
EPA Chemical Accident Prevention Provisions, also known as the Risk Management Plan requirements, which are designed to prevent the accidental release of toxic, reactive, flammable or explosive materials;
•
OSHA Process Safety Management Regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive materials; and
•
Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities.

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

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938 (NGA) exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis. Therefore, the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.

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

Interstate Pipelines

We own an interstate natural gas pipeline, located in Wyoming. Under the NGA, the 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 the FERC. In addition, the 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. If the FERC were to suspend our market-based rate authority, it could have an adverse impact on our revenue associated with the transportation service.

The Rendezvous interstate natural gas pipeline is subject to a number of the 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, the 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. The FERC also clarified in Order No. 717 that existing waivers to the standards of conduct shall continue in full force and effect. The 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.


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Market Behavior Rules

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (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 Natural Gas Policy Act of 1978 (NGPA) to give the FERC authority to impose civil penalties for violations of these statutes, up to $1.0 million per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, the FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines. In addition, the Commodities Futures Trading Commission (CFTC), is directed under the Commodities Exchange Act (CEA), to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1.0 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.

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

Petroleum Pipelines

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

EPAct 1992 required the FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, the FERC adopted an indexed rate methodology, which, as currently in effect, allows interstate petroleum pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (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,

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2016, pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 2.65%. The indexing methodology is applicable to existing rates with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but is permitted to do so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

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

Environmental Matters

General

Our operation of pipelines and other facilities for the gathering of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
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requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;
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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
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delaying system modification or upgrades during permit reviews;
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requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
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enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.

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

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

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather natural gas. 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, may cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Wastes

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, non-hazardous and hazardous solid wastes and petroleum hydrocarbons. These laws generally regulate the

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

We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act (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, become subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses or otherwise impose limits or restrictions on our operations or those of our customers.

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

Oil Pollution Act

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

Air Emissions

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

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On May 22, 2012, the EPA proposed amendments to the final

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rule in response to several petitions for reconsideration. The EPA proposed a final rule on June 7, 2012. The EPA finalized the proposed amendments on January 14, 2013. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on all our engines following prescribed maintenance practices for engines (which are substantially consistent with our existing practices), and implementing additional emissions testing and monitoring programs. Compliance with the final rule was required by October 2013 and has had a minor impact on our business.

In June 2011, the EPA issued the final New Source Performance Standards (NSPS) at subpart JJJJ of Title 40 of the C.F.R., modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The EPA issued minor amendments to the rule on January 14, 2013. The final rule and amendments have had minor impact on our business.

On August 16, 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. These new rules, located at part 60, subpart OOOO of Title 40 of the C.F.R., address emissions of various pollutants frequently associated with oil and natural gas production and processing activities. These final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. In addition, these regulations revise existing requirements for volatile organic compound emissions from equipment leaks at onshore natural gas processing plants by lowering the leak definition for valves from 10,000 parts per million to 500 parts per million, and requiring monitoring of connectors, pumps, pressure relief devices and open-ended lines. These regulations also establish requirements regarding emissions from: (i) wet seal and reciprocating compressors at gathering systems, boosting facilities, and onshore natural gas processing plants, effective October 15, 2012; (ii) specified pneumatic controllers at onshore oil and natural gas production well sites, gathering systems, boosting facilities, and onshore natural gas processing plants, effective October 15, 2013; and (iii) specified storage vessels at onshore oil and natural gas production well sites, gathering systems, boosting facilities, onshore natural gas processing plants, onshore natural gas transmission systems, and underground natural gas storage facilities, effective October 15, 2013. However, acting upon the multiple petitions for reconsideration it received, the EPA published a proposed rule on April 12, 2013, which would extend the compliance date for controlling regulated emissions from storage vessels constructed, modified or re-constructed after April 12, 2013 to the later of April 15, 2014 or 60 days after startup, and allowing those storage vessels constructed, modified or re-constructed between August 23, 2011 and April 15, 2013 to only provide notice of their existence by October 15, 2013, unless their emissions increase after April 15, 2013, in which event the April 14, 2014 date would apply to them as well. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

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

Water Discharges

The Federal Water Pollution Control Act (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

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compliance with existing permits and compliance with foreseeable new permit requirements under the Clean Water Act and state counterparts will not have a material adverse effect on our financial condition, results of operations or cash flow.

Safe Drinking Water Act

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

Endangered Species

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

National Environmental Policy Act

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

Climate Change

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

In addition, on September 2009, the EPA issued a final rule requiring the reporting of GHG from specified large GHG emission sources in the United States beginning in 2011 for emissions in 2010. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We own and operate facilities that are subject to reporting requirements under the EPA's GHG emission reporting rules. We have been reporting under this requirements on our facilities since 2011.

While Congress has from time to time considered legislation to reduce emissions of GHG, 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 primarily 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 GHG. Some states have also

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adopted or proposed regulations for methane leak detection monitoring and repair specific to the upstream and midstream sectors of the oil and gas industry. In fact, in February 2014, the Colorado Air Quality Control Commission adopted new regulations that regulate volatile organic compound emissions from storage tanks and dehydrators beyond the federal requirements, noted above, and also regulate all hydrocarbon emissions, including methane emissions, through rigorous Leak Detection and Repair requirements for oil and gas facilities upstream of gas processing plants. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHG or otherwise limit emissions of GHG from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHG 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 GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur in areas where we operate, they could have in adverse effect on our assets and operations.

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

Hydraulic Fracturing

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

Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. The EPA released a progress report on its study on December 21, 2012, and stated that a draft report of the findings of the study is expected in late 2014 for peer review and comment, with a final report expected to be issued in 2016. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. In addition, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.

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

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

Further, on August 16, 2012, the EPA published final rules that subject oil and natural gas operations (including production, processing, transmission, storage and distribution) to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically-fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flowback emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use the REC techniques, with or with combustion devices, after January 1, 2015. However, EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. EPA did propose some revised rules on April 12, 2013, which are responsive to some of these requests concerning regulated tank requirements, and is further reconsidering other aspects of the proposed rules which were the subject of petitions for reconsideration. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

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

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

Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security (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 DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information.

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


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Significant Customers

The Partnership's five largest customers accounted for 94% in aggregate of QEP Midstream's revenues from August 14, 2013 to December 31, 2013. Management believes that there is a low risk of loss of any of these customers as a result of the existing contractual agreements, and therefore, a limited risk to the financial position or results of operations of QEP Midstream. During the year ended December 31, 2013, QEP accounted for 68% of the Partnership's total revenues and QGC accounted for 16% of the Partnership's total revenues.

Employees

We are managed and operated by the executive officers of the General Partner with oversight provided by the Board of Directors of the General Partner (the Board). Neither we nor our subsidiaries have any employees. The General Partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of the General Partner. As of December 31, 2013, the General Partner and its affiliates have approximately 250 employees performing services for our operations. We believe that our General Partner and its affiliates have a satisfactory relationship with those employees.


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ITEM 1A. RISK FACTORS
 
Investors should read carefully the following factors as well as the cautionary statements referred to in "Forward-Looking Statements" herein. If any of the risks and uncertainties described below or elsewhere in this Annual Report actually occur, the Partnership's business, financial condition or results of operations could be materially adversely affected.

We May Not Have Sufficient Cash from Operations Following the Establishment of Cash Reserves and Payment of Fees and Expenses, Including Cost Reimbursements to Our General Partner, to Enable Us to Pay the Minimum Quarterly Distribution, or Any Distribution, to Holders of Our Common and Subordinated Units. In order to pay the minimum quarterly distribution of $0.25 per unit per quarter, or $1.00 per unit on an annualized basis, we will require available cash of approximately $13.6 million per quarter, or $54.5 million per year, based on the number of common and subordinated units outstanding as of the end of the period. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
•
the volume of natural gas and oil we gather;
•
the level of production of oil and natural gas and the resultant market prices of oil, gas, and NGL;
•
damage to the pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third party pipelines or facilities upon which we rely for transportation of services;
•
leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;
•
prevailing economic and market conditions;
•
capacity charges and volumetric fees associated with our transportation services;
•
the level of competition from other midstream energy companies in our geographic markets;
•
the level of our operating, maintenance and general and administrative costs; and
•
regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
•
the level of capital expenditures we make;
•
the cost of acquisitions, if any;
•
fluctuations in cash generated by operations, including the seasonality of our business and customer payment issues;
•
our debt service requirements and other liabilities;
•
fluctuations in our working capital needs;
•
our ability to borrow funds and access capital markets and the cost of obtaining those funds;
•
restrictions contained in our debt agreements;
•
the amount of cash reserves established by our General Partner; and
•
other business risks affecting our cash levels

The Amount of Cash We Have Available for Distribution to Holders of Our Common and Subordinated Units Depends Primarily on Our Cash Flow Rather Than on Our Profitability, Which May Prevent Us from Making Distributions, Even During Periods in Which We Record Net Income. The amount of cash we have available for distribution depends primarily upon our cash flow, which will be affected by non-cash items, and not solely on profitability. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Because of the Natural Decline in Production from Existing Wells in Our Areas of Operation, Our Success Depends, in Part, on Producers Replacing Declining Production and Also on Our Ability to Secure New Sources of Natural Gas and Crude Oil. Any Decrease in the Volumes of Natural Gas or Crude Oil that We Gather Could Adversely Affect Our Business and Operating Results. The natural gas and crude oil volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas and crude oil. The primary factors affecting our ability to obtain non-dedicated sources of natural gas and crude oil include (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.


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We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:
•
the availability and cost of capital;
•
prevailing and projected oil, natural gas and NGL prices;
•
demand for oil, natural gas and NGL;
•
levels of reserves;
•
geological considerations;
•
environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
•
the availability of drilling rigs and other costs of production and equipment.

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

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

We Do Not Intend to Obtain Independent Evaluations of Oil and Natural Gas Reserves Connected to Our Gathering and Transportation Systems on a Regular or Ongoing Basis; Therefore, in the Future, Volumes of Oil and Natural Gas on Our Systems Could Be Less Than We Anticipate. We do not intend to obtain independent evaluations of oil and natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate, and we are unable to secure additional sources of oil or natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our Success Depends on Drilling Activity and 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, financial condition and our ability to make cash distributions to our unitholders.

Natural Gas and Crude Oil Prices are Volatile, and a Change in These Prices in Absolute Terms, or an Adverse Change in the Prices of Natural Gas and Crude Oil Relative to One Another, Could Adversely Affect Our Cash Flow and Our Ability to Make Cash Distributions to Our Unitholders. The markets for and prices of natural gas, crude oil and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:
•
worldwide economic conditions;
•
worldwide political events, including actions taken by foreign oil and natural gas producing nations;
•
worldwide weather events and conditions, including natural disasters and seasonal changes;
•
the levels of domestic production and consumer demand;
•
the availability of transportation systems with adequate capacity;
•
the volatility and uncertainty of regional pricing differentials;
•
the price and availability of the petroleum products we gather and of alternative fuels;
•
the effect of energy conservation measures;
•
the nature and extent of governmental regulation and taxation;
•
fluctuations in demand from electronic power generators and industrial customers; and
•
the anticipated future prices of oil, natural gas and other commodities.

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Changes in natural gas and crude oil prices both in absolute terms and in relation to one another could adversely affect our cash flow and our ability to make distributions to our unitholders.

We May Not Be Able to Increase Our Third-Party Throughput and Resulting Revenue Due to Competition and Other Factors, Which Could Limit Our Ability to Grow, and Extend Our Dependence on QEP. Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. For the year ended December 31, 2013, QEP accounted for approximately 68% of our total revenues. Our ability to increase our third-party throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. To the extent that we lack available capacity on our systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional oil and natural gas production in our areas of operation.

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

From Time to Time, We are Involved in Litigation, Claims and Other Proceedings that Could Have a Material Adverse Effect on Our Business, Results of Operations, Financial Condition and Ability to Make Cash Distributions to Our Unitholders. From time to time, we are involved in litigation, claims and other proceedings relating to the conduct of our business, including but not limited to claims related to the operation of our assets and the services we provide to our customers, as well as claims relating to environmental and regulatory matters. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur material costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Current accruals for such costs may be insufficient. Additionally, our insurance coverage may be insufficient to cover adverse judgments against us.

Our gathering systems are the subject of ongoing litigation between QGC and QEP Field Services. QEP Field Services’ former affiliate, QGC, filed its complaint in state court in Utah on May 1, 2012, asserting claims for (1) breach of contract, (2) breach of implied covenant of good faith and fair dealing, (3) an accounting and (4) declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) entered when the parties were affiliates. Under the 1993 Agreement, QEP Field Services provides gathering services for producing properties developed by former affiliate Wexpro Company on behalf of QGC’s utility ratepayers. QGC is disputing the annual calculation of the gathering rate, which is based on a cost of service concept expressed in the 1993 Agreement and in a 1998 amendment, and is netting this disputed amount from its monthly payment of the gathering fees to QEP Field Services. As of December 31, 2013, QEP has recorded $8.5 million of deferred revenue related to the QGC disputed amount. The annual gathering rate has been calculated in the same manner under the contract since it was amended in 1998, without any prior objection or challenge by QGC. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and declaratory judgment relating to its gathering services under the same agreement. It is possible that QGC may amend its complaint to add us as a defendant in the litigation. Refer to "Item 3. Legal Proceedings" for additional information related to the QGC litigation.

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

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

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

Some of Our Gathering Agreements Contain Provisions that can Reduce the Cash Flow Stability that the Agreements were Designed to Achieve. Several of our gathering agreements related to our Vermillion, Three Rivers and Williston gathering systems contain minimum volume commitments that are designed to generate stable cash flows to us from our customers over a specified period of time, while also minimizing direct commodity price risk. Under these minimum volume commitments, our customers agree to ship a minimum volume of natural gas or oil on our gathering systems over certain periods during the term of the agreement. In addition, certain of our gathering agreements also include an aggregate minimum volume commitment, which is a total amount of natural gas or oil that the customer must transport on our gathering systems over a term specified in the agreement. In these cases, once a customer achieves its aggregate minimum volume commitment, any remaining future minimum volume commitments will terminate and the customer will then simply pay the applicable gathering rate multiplied by the actual throughput volumes shipped.

If a customer’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract year or the term of the minimum volume commitment, as applicable. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. To the extent that a customer’s actual throughput volumes are above or below its minimum volume commitment for the applicable period, several of our gathering agreements with minimum volume commitments contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments in subsequent periods. These provisions include the following:
•
To the extent that a customer’s throughput volumes are less than its minimum volume commitment for the applicable period and the customer makes a deficiency payment, it is entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, we would not receive gathering fees on throughput in excess of a customer’s applicable minimum volume commitment (depending on the terms of the specific gathering agreement) to the extent that the customer had made a deficiency payment with respect to one or more preceding years.
•
To the extent that a customer’s throughput volumes exceed its minimum volume commitment in the applicable period, it is entitled to apply the excess throughput against its aggregate minimum volume commitment, thereby reducing the period for which its annual minimum volume commitment applies. For example, one of our customers has a contracted minimum volume commitment term from December 2007 through December 2017. Should this customer continually ship volumes in excess of its minimum volume commitment, the average remaining period for which our minimum volume commitments apply could be less than the average of the original stated terms of our minimum volume commitment.
•
To the extent that a customer’s throughput volumes exceed its minimum volume commitment for the applicable period, there is a crediting mechanism that allows the customer to build a “bank” of credits that it can utilize in the future to reduce deficiency payments owed in subsequent periods, subject to expiration if there is no deficiency payment owed in subsequent periods. The period over which this credit bank can be applied to future deficiency payments varies, depending on the particular gathering agreement.

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

We Depend on a Relatively Limited Number of Customers for a Significant Portion of Our Revenues. The Loss of, or Material Nonpayment or Nonperformance By, Any One or More of These Customers Could Adversely Affect Our Ability to Make Cash Distributions Our Unitholders. A significant percentage of our revenue is attributable to a relatively limited number of customers. Our top ten customers accounted for over 90% of our revenue for the year ended December 31, 2013. We have gathering contracts with each of these customers of varying duration and commercial terms. If we were unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in

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a timely fashion, on favorable terms or at all. QEP and QGC accounted for approximately 68% and 16%, 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. Further, we undertake capital expenditures based on commitments from customers which we rely upon to realize the expected return on those expenditures, and nonperformance by our customers on those commitments could result in substantial losses to us. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders. In any of these situations, our revenues and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively limited number of customers for a substantial portion of our revenue.

If Third-Party Pipelines or Other Midstream Facilities Interconnected to Our Gathering or Transportation Systems Become Partially or Fully Unavailable, or If the Volumes We Gather or Transport Do Not Meet the Natural Gas Quality Requirements of Such Pipelines or Facilities, Our Gross Operating Margin and Cash Flow and Our Ability to Make Distributions to Our Unitholders Could Be Adversely Affected. Our gathering and transportation pipelines connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as the Kern River Pipeline, the Northwest Pipeline, the Rockies Express Pipeline and others. The continuing operation of such third-party pipelines, processing plants and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our gross margin and ability to make cash distributions to our unitholders could be adversely affected.

Our Business Is Subject to Federal, State and Local Laws and Regulations that Govern the Product Quality Specifications of the Products that We Transport or Sell. Petroleum products that we transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications for commodities sold into the public market. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. If we are unable to recover these costs through increased revenues, our cash flows and ability to pay cash distributions could be materially adversely affected.

Our Business Involves Many Hazards and Operational Risks, Some of Which May Not Be Fully Covered By Insurance. If a Significant Accident or Event Occurs for Which We Are Not Adequately Insured, or If We Fail to Recover All Anticipated Insurance Proceeds for Significant Accidents or Events for Which We Are Insured, Our Operations and Financial Results Could Be Adversely Affected. Our operations are subject to all of the risks and hazards inherent in the gathering of oil and natural gas, including:
•
damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters, acts of terrorism and actions by third parties;
•
damage from construction, vehicles, farm and utility equipment or other causes;
•
leaks of oil, natural gas and other hydrocarbons or losses of oil or natural gas as a result of the malfunction of equipment or facilities;
•
ruptures, fires and explosions; and
•
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These and similar risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could also have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of

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coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

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

We Intend to Grow Our Business in Part By Seeking Strategic Acquisition Opportunities. If We Are Unable to Make Acquisitions on Economically Acceptable Terms from QEP or Third Parties, Our Future Growth Will Be Affected. In Addition, the Acquisitions We Do Make May Reduce, Rather Than Increase, Our Cash Generated from Operations on a Per Unit Basis. Our ability to grow is affected, in part, by our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including QEP. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

If we are unable to make accretive acquisitions from QEP or third parties, whether because we are (i) unable to identify attractive acquisition prospects or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
•
mistaken assumptions about volumes, revenue, costs and synergies;
•
an inability to secure adequate customer commitments to use the acquired systems or facilities;
•
coordinating geographically disparate organizations, systems and facilities;
•
the assumption of unknown liabilities for which we have no recourse under applicable indemnification provisions;
•
limitations on the right to indemnity from the seller;
•
mistaken assumptions about the overall costs of equity or debt;
•
the diversion of management's and employees' attention from other business concerns;
•
unforeseen difficulties operating in new geographic areas and business lines; and
•
customer or key employee losses at the acquired businesses.

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

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


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

The Credit and Risk Profile of Our General Partner and Its Owner, QEP, Could Adversely Affect Our Credit Ratings and Risk Profile, Which Could Increase Our Borrowing Costs or Hinder Our Ability to Raise Capital. The credit and business risk profiles of our General Partner and QEP may be factors considered in credit evaluations of us. This is because our General Partner, which is owned by QEP, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of QEP, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of QEP’s grade credit rating, may adversely affect our credit ratings and risk profile. If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our General Partner or QEP, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of QEP and its subsidiaries because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.

Because Our Common Units Will Be Yield-Oriented Securities, Increases in Interest Rates Could Adversely Impact Our Unit Price, Our Ability to Issue Equity or Incur Debt for Acquisitions or Other Purposes and Our Ability to Make Cash Distributions at Our Intended Levels. Interest rates may increase in the future. As a result, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Debt We Incur in the Future May Limit Our Flexibility to Obtain Financing and to Pursue Other Business Opportunities.
We currently have no debt and $500.0 million available for future borrowings under our credit facility. Our future level of debt could have important consequences for us, including the following:
•
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•
our funds available for operations, future business opportunities and cash distributions to unitholders may be reduced by that portion of our cash flow required to make interest payments on our debt;
•
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
•
our flexibility in responding to changing business and economic conditions may be limited.

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

A Shortage of Skilled Labor in the Midstream Industry Could Reduce Labor Productivity and Increase Costs, Which Could Have a Material Adverse Effect on Our Business and Results of Operations. The gathering of oil and natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor costs and overall productivity could be materially and adversely affected. If our labor costs increase or if we experience materially increased health and benefit costs with respect to our General Partner’s employees, our results of operations could be materially and adversely affected.

Restrictions in Our Credit Facility Could Adversely Affect Our Business, Financial Condition, Results of Operations, Ability to Make Distributions to Unitholders and Value of Our Common Units. On August 14, 2013, in connection with the closing of the IPO, we entered into a $500.0 million senior secured revolving credit facility (the Credit Facility). The Credit Facility is likely to limit our ability to, among other things:
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incur our guarantee additional debt;
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make distributions on or redeem or repurchase units;
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make certain investments and acquisitions;
•
make capital expenditures;

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•
incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
•
transfer, sell or otherwise dispose of assets.

The Credit Facility also includes 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 may not be able to meet those ratios and tests.

The provisions of the 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 the Credit Facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

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

Due to Our Lack of Industry Diversification, Adverse Developments in Our Segment of the Midstream Energy Industry Could Adversely Impact Our Financial Condition, Results of Operations and Cash Flows and Reduce Our Ability to Make Cash Distributions to Our Unitholders. Our operations are focused on oil and gas gathering and transportation services. Due to our lack of industry diversification, adverse developments in our current segment of the midstream industry could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified.

Certain of Our Gathering Systems, Including Our Operations in the Bakken Shale, Are Located On Native American Tribal Lands and Are Subject to Various Federal and Tribal Approvals and Regulations, Which May Increase Our Costs and Delay or Prevent Our Efforts to Conduct Planned Operations. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, BLM, and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue our operations on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas and oil gathering operations on such lands.

Increased Regulation of Hydraulic Fracturing Could Result in Reductions or Delays in Oil and Natural Gas Production By Our Customers, Which Could Adversely Impact Our Revenues. A portion of our customers’ oil and natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and a small amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, from time to time, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Refer to Item 1, Environmental Matters, of Part I of this Annual Report on Form 10-K for more information on the current and ongoing regulations over hydraulic fracturing.

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

Our Construction of New Assets May Not Result in Revenue Increases and Will Be Subject to Regulatory, Environmental, Political, Legal and Economic Risks, Which Could Adversely Affect Our Results of Operations and Financial Condition. One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Costs overruns or unanticipated delays in the completion or commercial development of these projects could reduce the anticipated returns on these projects, which in turn could materially increase our leverage and reduce our liquidity and our ability to pay cash distributions. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not occur or only occurs over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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

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

Our Gathering Systems Are Subject to State Regulation That Could Materially and Adversely Affect Our Operations and Cash Flows. State regulation of gathering facilities includes safety and environmental requirements. Several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates

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and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations or may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our operations and revenues.

Two of Our Pipelines Are Regulated by the FERC, Which May Adversely Affect Our Revenues and Results of Operations. We own an interstate gas pipeline company, Rendezvous Pipeline, which is regulated by the FERC under the NGA. The FERC has approved market-based rates for Rendezvous Pipeline allowing it to charge rates that customers will accept. The FERC has also established rules, policies and practices across the range of its natural gas regulatory activities, including, for example, policies on open access transportation, construction of new facilities, market transparency, market manipulation, ratemaking, capacity release, segmentation and market center promotion, which both directly and indirectly affect our business, and could materially and adversely affect our operations and revenues.

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

We Are Subject to Stringent Environmental Laws and Regulations That May Expose Us to Significant Costs and Liabilities.
Our oil and natural gas gathering operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
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the federal CAA and analogous state laws that restrict emissions of air pollutants from any sources and impose obligations related to pre-construction activities and monitoring and reporting air emissions;
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the CERCLA and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
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the Clean Water Act and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
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the OPA and analogous state laws that establish strict liability for releases of oil into waters of the United States;
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the RCRA and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;
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the ESA that restricts activities that may affect endangered and threatened species or their habitats; and
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the federal Toxic Substances Control Act and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Numerous governmental authorities, such as the 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

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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. Refer to Item 1, Environmental Matters, of Part I of this Annual Report on Form 10-K for more information on the current and ongoing regulations.

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 NGPSA, and the HLPSA, as amended by the PSA, the APSA, the PSIA, the PIPES Act, and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (2011 Pipeline Safety Act), the DOT, through the 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. In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. 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. See Item 1, Safety and Maintenance, of Part I of this Annual Report on Form 10-K for more information on the specific regulations.

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 GHG, 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.

Nevertheless, the Obama Administration announced on June 25, 2013, the President’s Climate Action Plan to cut carbon pollution under existing statutory authority, primarily Clean Air Act Section 111(d). 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, though some have proposed or adopted methane leak detection monitoring and repair requirements specific to the upstream and midstream oil and gas sectors. Most of the cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to GHG-related regulation, including methane leak detection and repair requirements. 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, or both.

Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, in December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHG present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHG under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, in September 2009, the EPA issued a final rule requiring the monitoring and reporting of GHG emissions from specified large greenhouse gas emission sources in the United States and, in November 2010, expanded this existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year, requiring reporting of GHG emissions by regulated petroleum and natural gas facilities to the EPA beginning in 2012 and annually thereafter. Currently, it is anticipated that several of our facilities will likely be required to report under this rule. However, operational or regulatory changes could require some or all of our other facilities to be required to report GHG emissions at a future date. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. Several of the EPA’s GHG rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.


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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 GHG 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.

The Adoption and Implementation of New Statutory and Regulatory Requirements for Swap Transactions Could Have an Adverse Impact on Our Ability to Hedge Risks Associated With Our Business and Increase the Working Capital Requirements to Conduct These Activities. In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted. The Dodd-Frank Act requires the CFTC and the SEC to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps entities, the clearing of certain swaps, the reporting and recordkeeping of swaps, and expanded enforcement such as establishing position limits. Although the Commodities Futures Trading Commission established position limits on certain core futures and equivalent swaps contracts, including natural gas, with exceptions for certain bona fide hedging transactions, those limits were vacated by the federal district court on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the CFTC proposed a new position limits rule, which would limit trading in certain futures and swap contracts. Comments on the proposed rule were due by February 10, 2014. We cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on our business.

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

If Our Services Agreement with QEP is Terminated, We Will Have to Obtain Those Services Internally or Through Third-Party Arrangements. We depend on QEP to provide us certain general and administrative services and any additional services we may request pursuant to our Omnibus Agreement. QEP’s provision of general and administrative services to us under the Omnibus Agreement will continue until QEP no longer controls our General Partner. In December 2013, the Board of Directors of QEP authorized the separation of its midstream business, including its ownership and control of the general and limited partner interests in QEP Midstream. If QEP ceases to control the General Partner, either QEP or we may terminate the Omnibus Agreement. If the Omnibus Agreement is terminated, we will have to obtain these services internally or through third-party arrangements, which may result in increased costs to us.

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

If We Fail to Develop or Maintain an Effective System of Internal Controls, We May Not Be Able to Report Our Financial Results Timely and Accurately or Prevent Fraud, Which Would Likely Have a Negative Impact on the Market Price of Our Common Units. We prepare our financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things,

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to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.

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

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

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

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

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

Risks Inherent in an Investment in Us

Our General Partner and Its Affiliates, Including QEP, Have Conflicts of Interest with Us and Limited Duties to Us and Our Unitholders, and They May Favor Their Own Interests to Our Detriment and That of Our Unitholders. Additionally, We Have No Control Over QEP’s Business Decisions and Operations, and QEP is Under No Obligation to Adopt a Business Strategy That Favors Us. QEP owns a 2.0% general partner interest and a 55.8% limited partner interest in us and owns and controls our General Partner. Although our General Partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is not adverse to the best interests of its owner, QEP. Conflicts of interest may arise between QEP and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the General Partner may favor its own interests and the interests of its affiliates, including QEP, over the interests of our common unitholders. These conflicts include, among others, the following situations:
•
neither our Partnership Agreement nor any other agreement requires QEP to pursue a business strategy that favors us, and the directors and officers of QEP have a fiduciary duty to make these decisions in the best interests of the stockholders of QEP. QEP may choose to shift the focus of its investment and growth to areas not served by our assets;
•
QEP may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
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Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

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•
except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
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our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
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our General Partner determines the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our General Partner, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units;
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our General Partner determines which costs incurred by it are reimbursable by us;
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our General Partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;
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our Partnership Agreement permits us to classify up to $40.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our General Partner in respect of the general partner interest or the incentive distribution rights;
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our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our General Partner intends to limit its liability regarding our contractual and other obligations;
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our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of the common units;
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our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates;
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our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and
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our General Partner may cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the Conflicts Committee of the Board of Directors of our General Partner, which we refer to as our Conflicts Committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.

Our Partnership Agreement Requires That We Distribute All of Our Available Cash, Which Could Limit Our Ability to Grow and Make Acquisitions. Our Partnership Agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our Partnership Agreement or our Credit Facility on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.

While Our Partnership Agreement Requires Us to Distribute All of Our Available Cash, Our Partnership Agreement, Including the Provisions Requiring Us to Make Cash Distributions, May Be Amended. While our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including the provisions requiring us to make cash distributions, may be amended. Our Partnership Agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our Partnership Agreement can be amended with the consent of our General Partner and the approval of a majority of the outstanding common units (including common units held by QEP)

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after the subordination period has ended. As of December 31, 2013, QEP owns 6.8% of the outstanding common units and all of our outstanding subordinated units.

Our Partnership Agreement Restricts the Remedies Available to Holders of Our Common and Subordinated Units for Actions Taken By Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty. Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:
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provides that whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
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provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith;
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provides that our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
•
provides that our General Partner will not be in breach of its obligations under our Partnership Agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our Partnership Agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our Partnership Agreement provides that any determination by our General Partner must be made in good faith, and that our Conflicts Committee and the Board of Directors of our General Partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

Common Units Held by Unitholders Who Are Not Both a Citizenship Eligible Holder and a Rate Eligible Holder May Be Subject to Redemption. In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body, and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. Unitholders who do not meet the requirements to be a citizenship eligible holder and a rate eligible holder run the risk of having their units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner. In addition, unitholders who do not meet the requirements to be a citizenship eligible holder will not be entitled to voting rights.

Cost Reimbursements, Which Will Be Determined in Our General Partner’s Sole Discretion, and Fees Due Our General Partner and Its Affiliates for Services Provided Will Be Substantial and Will Reduce Our Cash Available for Distribution to Our Unitholders. Under our Partnership Agreement, we are required to reimburse our General Partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our Omnibus Agreement, our General Partner determines the amount of these expenses. Under the terms of the Omnibus Agreement we will be required to reimburse QEP for the provision of certain general and administrative services to us. Our General Partner and its affiliates also may provide us other services for which we will be charged fees as determined by

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our General Partner. Payments to our General Partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders.

Unitholders Have Very Limited Voting Rights and, Even If They Are Dissatisfied, They Cannot Remove Our General Partner Without Its Consent. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the Board of Directors of our General Partner and will have no right to elect our General Partner or the Board of Directors of our General Partner on an annual or other continuing basis. The Board of Directors of our General Partner is chosen by the members of our General Partner, which are wholly owned subsidiaries of QEP. Furthermore, if our unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our unitholders are currently unable to remove our General Partner without its consent, because our General Partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our General Partner. As of December 31, 2013, our General Partner and its affiliates own 57.8% of the common units and subordinated units. Also, if our General Partner is removed without cause during the subordination period and common units and subordinated units held by our General Partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our General Partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

“Cause” is narrowly defined under our Partnership Agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful or wanton misconduct in its capacity as our General Partner. Cause does not include most cases of charges of poor management of the business, so the removal of our General Partner, because of our unitholders’ dissatisfaction with our General Partner’s performance in managing our partnership would most likely result in the termination of the subordination period.

Furthermore, our unitholders’ voting rights are further restricted by the provision in our Partnership Agreement providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the Board of Directors of our General Partner, cannot vote on any matter.

Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our General Partner Interest or the Control of Our General Partner May Be Transferred to a Third Party Without Unitholder Consent. Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our Partnership Agreement on the ability of QEP to transfer its membership interest in our General Partner to a third party. In December 2013, the Board of Directors of QEP authorized the separation of its midstream business, including the ownership and control of its general and limited partner interests in QEP Midstream. Following the separation, the new partners of our General Partner would be in a position to replace the Board of Directors and officers of our General Partner with their own choices and to control the decisions taken by the Board of Directors and officers.

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

We May Issue Additional Units Without Unitholder Approval, Which Would Dilute Unitholder Interests. At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our

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unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our Partnership Agreement nor our Credit Facility prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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the ratio of taxable income to distributions may decrease;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of our common units may decline.

QEP May Sell Units in the Public or Private Markets, and Such Sales Could Have an Adverse Impact on the Trading Price of the Common Units. QEP currently holds common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide QEP with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our General Partner’s Discretion in Establishing Cash Reserves May Reduce the Amount of Cash Available for Distribution to Unitholders. Our Partnership Agreement requires our General Partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the Partnership Agreement permits the General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Affiliates of Our General Partner, Including QEP, May Compete with Us, and Neither Our General Partner Nor Its Affiliates Have Any Obligation to Present Business Opportunities to Us. Neither our Partnership Agreement nor our Omnibus Agreement will prohibit QEP or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, QEP and other affiliates of our General Partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from QEP and other affiliates of our General Partner could materially adversely impact our results of operations and cash available for distribution to unitholders.

Our General Partner Has a Limited Call Right That May Require Unitholders to Sell Their Common Units at an Undesirable Time or Price. If at any time our General Partner and its affiliates own more than 80.0% of our common units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2013, our General Partner and its affiliates own approximately 13.9% of our common units. At the end of the subordination period (which could occur as early as September 30, 2014), assuming no additional issuances of common units (other than upon the conversion of the subordinated units) and no exercise of the underwriters’ option to purchase additional common units, our General Partner and its affiliates will own approximately 56.9% of our common units.

Unitholder Liability May Not Be Limited if a Court Finds That Unitholder Action Constitutes Control of Our Business. A General Partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. A unitholder could be liable for our obligations as if the unitholder were a general partner if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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a unitholder's right to act with other unitholders to remove or replace the General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

Unitholders May Have to Repay Distributions That Were Wrongfully Distributed to Them. Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities

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to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our General Partner, or Any Transferee Holding Incentive Distribution Rights, May Elect to Cause Us to Issue Common Units and General Partner Units to It in Connection with a Resetting of the Target Distribution Levels Related to Its Incentive Distribution Rights, Without the Approval of Our Conflicts Committee or the Holders of Our Common Units. This Could Result in Lower Distributions to Holders of Our Common Units. Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%, in addition to distributions paid on its 2.0% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our General Partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our General Partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our General Partner on the incentive distribution rights in the prior two quarters. Our General Partner will also be issued the number of general partner units necessary to maintain our general partner’s interest in us at the level that existed immediately prior to the reset election. We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our General Partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units and general partner units in connection with resetting the target distribution levels. Additionally, our General Partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the General Partner relative to resetting target distributions if our General Partner concurs that the tests for resetting target distributions have been fulfilled.

The NYSE Does Not Require a Publicly Traded Limited Partnership Like Us to Comply with Certain of Its Corporate Governance Requirements. Our common units are currently traded on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our General Partner’s Board of Directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to shareholders of corporations that are subject to all of the NYSE corporate governance requirements.

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

Tax Risks Related to Owning our Common Units

Our Tax Treatment Depends on Our Status as a Partnership for Federal Income Tax Purposes. If the Internal Revenue Services (IRS) Were to Treat Us as a Corporation for Federal Income Tax Purposes, Which Would Subject Us to Entity-Level Taxation, Then Our Cash Available for Distribution to Our Unitholders Would Be Substantially Reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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

Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

If We Were Subjected to a Material Amount of Additional Entity-Level Taxation By Individual States, It Would Reduce Our Cash Available for Distribution to Our Unitholders. Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to unitholders. Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

The Tax Treatment of Publicly Traded Partnerships or an Investment in Our Common Units Could Be Subject to Potential Legislative, Judicial or Administrative Changes and Differing Interpretations, Possibly on a Retroactive Basis. The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

Our Unitholders’ Share of Our Income Will Be Taxable to Them for Federal Income Tax Purposes Even If They Do Not Receive Any Cash Distributions from Us. Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax Gain or Loss on the Disposition of Our Common Units Could Be More or Less Than Expected. If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of a unitholder's common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, a unitholder that sells common units, may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt Entities and Non-U.S. Persons Face Unique Tax Issues from Owning Our Common Units That May Result in Adverse Tax Consequences to Them. Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our

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income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

We Will Treat Each Purchaser of Common Units as Having the Same Tax Benefits Without Regard to the Actual Common Units Purchased. The IRS May Challenge This Treatment, Which Could Adversely Affect the Value of the Common Units. Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from our unitholders' sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholder's tax returns.

We Prorate Our Items of Income, Gain, Loss and Deduction for Federal Income Tax Purposes Between Transferors and Transferees of Our Units Each Month Based Upon the Ownership of Our Units on the First Day of Each Month, Instead of on the Basis of the Date a Particular Unit is Transferred. The IRS May Challenge This Treatment, Which Could Change the Allocation of Items of Income, Gain, Loss and Deduction Among Our Unitholders. We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A Unitholder Whose Common Units Are Loaned to a “Short Seller” to Effect a Short Sale of Common Units May Be Considered as Having Disposed of Those Common Units. If So, He Would No Longer Be Treated for Federal Income Tax Purposes as a Partner With Respect to Those Common Units During the Period of the Loan and May Recognize Gain or Loss from the Disposition. Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We Will Adopt Certain Valuation Methodologies and Monthly Conventions for Federal Income Tax Purposes That May Result in a Shift of Income, Gain, Loss and Deduction Between Our General Partner and Our Unitholders. The IRS May Challenge This Treatment, Which Could Adversely Affect the Value of the Common Units. When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our General Partner and certain of our unitholders.

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

The Sale or Exchange of 50.0% or More of Our Capital and Profits Interests During Any Twelve-Month Period Will Result in the Termination of Our Partnership for Federal Income Tax Purposes. We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests

49


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

As a Result of Investing in Our Common Units, Our Unitholders May Become Subject to State and Local Taxes and Return Filing Requirements in Jurisdictions Where We Operate or Own or Acquire Properties. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in Colorado, North Dakota, Utah and Wyoming. Some of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. Unitholders are responsible for filing their own federal, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS
 
None.

ITEM 3. LEGAL PROCEEDINGS

Our gathering systems are the subject of ongoing litigation between QGC and QEP Field Services, Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services’ former affiliate QGC filed its complaint in state court in Utah on May 1, 2012, asserting claims for 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 the parties were affiliates. Under the 1993 Agreement, certain of our systems provide gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the 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 IPO, the assets and agreement discussed above were assigned to the Partnership. QGC was netting the disputed amount from its monthly payment of the gathering fees to QEP Field Services and has continued to net such amount from its monthly payment to the Partnership. As of December 31, 2013, the Partnership has deferred revenue of $8.5 million related to the QGC disputed amount. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (as defined in Note 4 - Related Party Transactions, in Item 8 of this Annual Report on Form 10-K).

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

ITEM 4. MINE SAFETY DISCLOSURES
 
None.

50


PART II. OTHER INFORMATION

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

QEP Midstream’s common units have been listed on the NYSE under the symbol “QEPM” since August 9, 2013. Prior to that date, the Partnership’s equity securities were not listed on any exchange or traded on any public trading market. Prior to the IPO, the operations comprising the Partnership were owned by QEP. The following table sets forth the high and low sales prices reflected in the NYSE Composite Transactions of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter from the closing of the IPO through December 31, 2013.
 
Unit Price Range
 
 
 
High Price
 
Low Price
 
Distribution Per Common Unit
Third Quarter(1)
$
22.71

 
$
21.73

 
$
0.13
 
Fourth Quarter
23.83

 
21.84

 
0.26
 
            
(1) 
Since August 9, 2013, the commencement date of trading.

As of February 28, 2014, there were four registered holders of 23,008,998 outstanding common units held by the public, including 19,304,648 common units held in street name. In addition, as of February 28, 2014, QEP and its affiliates held 3,701,750 of our common units.

The Partnership has also issued 26,705,000 subordinated units and 1,090,117 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of the General Partner. During the subordination period (discussed below), the General Partner and its affiliates receive quarterly distributions on these units only after sufficient distributions have been paid to the common units. Set forth below under “Distributions of Available Cash” is a summary of the significant provisions of the Partnership Agreement that relate to distributions of available cash, minimum quarterly distributions and incentive distribution rights.

Distributions of Available Cash

The Partnership Agreement requires that, within 45 days after the end of each quarter beginning with the quarter ended September 30, 2013, we distribute all of our available cash to unitholders of record on the applicable record date. A cash distribution of $0.13 per common unit was declared on October 23, 2013, and was paid on November 14, 2013. A cash distribution of $0.26 per common unit was declared on January 23, 2014 and was paid on February 14, 2014.

Definition of Available Cash. Available cash is defined in the Partnership Agreement. Available cash generally means, for any quarter:
•
all cash and cash equivalents on hand at the end of that quarter;
•
less, the amount of cash reserves established by our General Partner to:
◦
provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);
◦
comply with applicable law, any of our debt instruments or other agreements; or
◦
provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters (provided that our General Partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
•
plus, if our General Partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our General Partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our Partnership Agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for

51


working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Subordinated Units and General Partner Units. During the subordination period, the common units have the right to receive a minimum quarterly distribution equal to $0.25 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions may be made on the subordinated units or the general partner units. The subordination period began on the closing date of the IPO and will extend until the first quarter after September 30, 2016 for which (i) distributions of at least $1.00 (the annualized minimum quarterly distribution) were made for each of the three immediately preceding four-quarter periods on all of the outstanding common units, subordinated units and general partner units; (ii) adjusted operating surplus (as defined in the Partnership Agreement) of at least $1.00 was generated during each of the three immediately preceding four-quarter periods on all of the common units, subordinated units and general partner units outstanding during those periods on a fully diluted basis; and (iii) there are no arrearages in payment of the minimum quarterly distribution on the common units. No arrearages will be paid on the subordinated units or the general partner units. The practical effect of subordinating the subordinated and general partner units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Intent to Distribute the Minimum Quarterly Distribution. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.25 per unit, or $1.00 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our General Partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement. Refer to Item 7 of Part II of this Annual Report on Form 10-K for a discussion of the restrictions included in our revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, our General Partner will be entitled to 2.0% of all quarterly distributions from inception that we make prior to our liquidation. This general partner interest is represented by 1,090,117 general partner units. Our General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The General Partner’s initial 2.0% interest in these distributions will be reduced if we issue additional units in the future and our General Partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

Our General Partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.3750 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our General Partner or its affiliates may receive on common, subordinated or general partner units that they own.

Percentage Allocations of Available Cash. The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our General Partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our General Partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount.” The percentage interests shown for our unitholders and our General Partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our General Partner include its 2.0% general partner interest and assume that our General Partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, that our General Partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
 
 
 
Total Quarterly Distribution
Per Unit Target Amount
 
Marginal Percentage Interest in
Distributions
 
 
Unitholders
 
General Partner
Minimum Quarterly Distribution
 
 
 
$0.2500
 
98.0
%
 
2.0
%
First Target Distribution
 
above $0.2500
 
up to $0.2875
 
98.0
%
 
2.0
%
Second Target Distribution
 
above $0.2875
 
up to $0.3125
 
85.0
%
 
15.0
%
Third Target Distribution
 
above $0.3125
 
up to $0.3750
 
75.0
%
 
25.0
%
Thereafter
 
 
 
above $0.3750
 
50.0
%
 
50.0
%


52


Recent Sales of Unregistered Securities; Purchases of Equity Securities by the Partnership and Affiliated Purchasers

The Partnership had no unregistered sales of securities during the fourth quarter of 2013. Neither the Partnership nor any affiliated purchaser purchased equity securities of the Partnership during the fourth quarter of 2013.

53


ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for the three years ended December 31, 2013, is provided in the table below. Refer to Item 7 and Item 8 in Part II of this Annual Report on Form 10-K for discussion of facts discussing the comparability of the Partnership's financial data.

QEP Midstream qualifies as an "emerging growth company" pursuant to the provisions of the JOBS Act. As a result, only three years of financial results are presented below. For additional information on the Partnership's status as an "emerging growth company," refer to Risk Factors in Item 1A of Part I of this Annual Report on Form 10-K. Further, the Partnership's results of operations subsequent to the IPO will not be comparable to the Predecessor's historical results of operations. For additional information on the comparability of financial statements, refer to Item 7 of Part II of this Annual Report on Form 10-K.
 
Year Ended
 
 
 
 
 
December 31, 2013
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
(in millions, except per unit information)
Results of Operations

 

 

 

Revenues
$
48.1

 
$
100.3

 
$
162.2

 
$
155.9

Operating income
20.3

 
40.2

 
72.4

 
71.8

Net income attributable to QEP Midstream or Predecessor
19.1

 
38.9

 
67.3

 
60.3

Net income attributable to QEP Midstream per limited partner unit (basic and diluted):

 

 

 

Common units
$
0.35

 
 
 
 
 
 
Subordinated units
0.35

 
 
 
 
 
 
Distributions per unit
$
0.39

 

 

 

Weighted-average limited partner units outstanding (basic and diluted):

 

 

 

Common units
26.7

 

 

 

Subordinated units
26.7

 

 

 

Financial Position (at period end)

 

 

 

Total Assets
$
579.9

 
$
685.6

 
$
725.4

 
$
714.3

Capitalization

 

 

 

Long-term debt
—

 
64.6

 
131.1

 
174.6

Total equity
527.6

 
577.4

 
552.3

 
502.4

Cash Flow From Continuing Operations

 

 

 

Net cash provided by operating activities
$
31.6

 
$
90.9

 
$
107.0

 
$
97.5

Capital expenditures
(14.2
)
 
(9.1
)
 
(43.7
)
 
(28.6
)
Net cash used in investing activities
(13.7
)
 
(8.5
)
 
(43.4
)
 
(28.5
)
Net cash used in financing activities
—

 
(82.7
)
 
(64.7
)
 
(68.0
)
Non-GAAP Measures

 

 

 

Adjusted EBITDA(1)
$
30.7

 
$
65.4

 
$
112.9

 
$
109.6

Distributable Cash Flow(1)
26.7

 
 
 
 
 
 
            
(1)
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures previously defined within this document. Management focuses on Adjusted EBITDA together with Distributable Cash Flow to assess the Partnership's operating results. See below for additional information and a reconciliation of Adjusted EBITDA and Distributable Cash Flow.


54


Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income attributable to the Partnership or the Predecessor and net cash flow from operating activities. The following table presents a reconciliation of Adjusted EBITDA and Distributable Cash Flow to net income attributable to the Partnership or the Predecessor, as applicable, and net cash provided by operating activities for each of the periods indicated.
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
 
(in millions)
Reconciliation of Net Income Attributable to QEP Midstream or Predecessor to Adjusted EBITDA and Distributable Cash Flows
 
 
Net income attributable to QEP Midstream or Predecessor
 
$
19.1


$
38.9


$
67.3

 
60.3

Interest expense, net of other income
 
0.9


2.6


8.6

 
12.7

Depreciation and amortization
 
11.7


25.0


39.8

 
38.3

Noncontrolling interest share of depreciation and amortization(1)
 
(1.0
)

(1.6
)

(2.8
)
 
(2.7
)
Deferred revenue associated with minimum volume commitment payments(2)
 
—

 
—

 
—

 
1.0

Net loss from asset sales
 
—


0.5


—

 
—

Adjusted EBITDA
 
$
30.7


$
65.4


$
112.9

 
$
109.6

Cash interest paid
 
(0.7
)




 
 
Maintenance capital expenditures
 
(13.1
)




 
 
Reimbursements for maintenance capital expenditures
 
9.6





 
 
Non-cash long-term compensation expense
 
0.2





 
 
Distributable Cash Flow
 
$
26.7





 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flows
 
 
Net cash provided by operating activities
 
$
31.6


$
90.9


$
107.0


97.5

Noncontrolling interest share of depreciation and amortization(1)
 
(1.0
)

(1.6
)

(2.8
)

(2.7
)
Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates
 
(0.1
)

(1.1
)

(0.6
)

(3.3
)
Net income attributable to noncontrolling interest
 
(1.5
)

(2.5
)

(3.7
)

(3.2
)
Interest expense
 
0.9


2.6


8.6


12.7

Deferred revenue associated with minimum volume commitment payments(2)
 
—

 
—

 
—

 
1.0

Working capital changes
 
1.4


(22.9
)

4.4


7.6

Amortization of deferred financing charges
 
(0.2
)

—


—


—

Equity-based compensation expense
 
(0.4
)

—


—


—

Adjusted EBITDA
 
$
30.7


$
65.4


$
112.9


$
109.6

Cash interest paid
 
(0.7
)









Maintenance capital expenditures
 
(13.1
)









Reimbursements for maintenance capital expenditures
 
9.6










Non-cash long-term compensation expense
 
0.2










Distributable Cash Flow
 
$
26.7











55


            
(1)
Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services.
(2) 
Several of our contracts contain minimum volume commitments that allow us to charge the customer a deficiency payment if the customer's actual throughput volumes are less than its minimum volume commitments for the applicable period. In certain contracts, if a customer makes a deficiency payment, that customer may be entitled to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in those periods exceed its minimum volume commitment. Depending on the specific terms of the contract, for GAAP accounting purposes, revenue under these agreements may be classified as deferred revenue and recognized once all contingencies or potential performance obligations associated with these related volumes have either (1) been satisfied through the gathering of future excess volumes of natural gas, or (2) expired or lapsed through the passage of time pursuant to terms of the applicable agreement. Deficiency payments that are recorded as deferred revenue are included in the calculation of our Adjusted EBITDA and Distributable Cash Flow in the period in which the deficiency payment is recorded rather than when they are recognized as revenue on the Consolidated Statement of Income.


56



ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (period prior to the IPO), refer to QEP Midstream Partners, LP Predecessor. References in this report to "QEP Midstream", the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after the IPO, in the present tense or prospectively (starting August 14, 2013), refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of this report, "QEP" refers to QEP Resources, Inc. and its consolidated subsidiaries.

Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to provide a reader of the financial statements with a narrative from the perspective of management on the financial condition, results of operations, liquidity and certain other factors that may affect the Partnership's operating results. MD&A should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of Part II of this Annual Report on Form 10-K.

Overview

QEP Midstream Partners, LP is a master limited partnership recently formed by QEP Resources, Inc. to own, operate, acquire and develop midstream energy assets.

On August 14, 2013, the Partnership's common units began trading on the NYSE after the completion of its IPO selling 20,000,000 common units, at a price to the public of $21.00 per common unit. 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. The Partnership received net proceeds of $449.6 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses of approximately $33.4 million. The Partnership used the net proceeds to repay its outstanding debt balance to QEP, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to the Partnership.

Following the IPO, the Partnership's assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota and consist of the following assets:

•
Green River System
◦
Green River Gathering Assets. The Green River Gathering Assets are comprised of 373 miles of natural gas gathering pipelines, 56 miles of crude oil gathering pipelines, 88 miles of water gathering pipelines and a 61-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have a total natural gas throughput capacity of 737 MMcf/d, total crude oil and condensate throughput capacity of 7,137 Bbls/d, total water throughput capacity of 21,990 Bbls/d, and a total of 40,800 Bbls/d throughput capacity on our FERC-regulated pipeline.
◦
Rendezvous Gas. Rendezvous Gas is a joint venture between QEP Midstream and 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 QEP Field Services or Western Gas. The Rendezvous Gas assets consist of three parallel, 103-mile high-pressure natural gas pipelines, with 1,032 MMcf/d of aggregate throughput capacity and 7,800 bhp of gas compression. We own a 78% interest in Rendezvous Gas.
◦
Rendezvous Pipeline. Rendezvous Pipeline's sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEP Field Services' Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 460 MMcf/d.

•
Vermillion Gathering System. The Vermillion Gathering System consists of gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah, which, when combined, include 517 miles of low-pressure, gas gathering pipelines and 23,932 bhp of gas compression. The Vermillion Gathering System has combined total throughput capacity of 212 MMcf/d.


57


•
Three Rivers Gathering System. Three Rivers Gathering is a joint venture between QEP Midstream and Ute Energy Midstream Holdings, LLC that was formed to transport natural gas gathered by Uintah Basin Field Services, an indirectly owned subsidiary in which QEP Field Services owns a 38% interest, and other third-party volumes to gas processing facilities owned by QEP Field Services and third parties. The Three Rivers Gathering System consists of gas gathering assets located in the Uinta Basin in northeast Utah, including approximately 52 miles of gathering pipeline and 4,735 bhp of gas compression. The Three Rivers Gathering System has total throughput capacity of 212 MMcf/d. We own a 50% interest in Three Rivers Gathering.

•
Williston Gathering System. The Williston Gathering System is a crude oil and natural gas gathering system located in the Williston Basin in McLean County, North Dakota. The Williston Gathering System includes 17 miles of gas gathering pipelines, 17 miles of oil gathering pipelines, 239 bhp of gas compression, and a crude oil and natural gas handling facility, located primarily on the Fort Berthold Indian Reservation. The Williston Gathering System has total crude oil throughput capacity of 7,000 Bbls/d and total natural gas throughput capacity of 3 MMcf/d.

In addition to the above assets, our Predecessor's assets included a 38% equity interest in Uintah Basin Field Services and a 100% interest in all other gathering assets that QEP Field Services owns in the Uinta Basin Gathering System (collectively referred to as the Uinta Basin Gathering System). These assets were retained by QEP Field Services and were not part of the assets conveyed to the Partnership in connection with the IPO.

The Results of Operations discussed below include historical information that relates to operations prior to the date of the IPO, which represents our Predecessor and includes combined results for both the properties conveyed to the Partnership in connection with the IPO and the properties retained by our Predecessor. Under "Supplemental Disclosures" below, we have included pro forma historical data limited to only the properties conveyed to us in connection with the IPO, as we believe such data is more useful to the reader to better understand trends in our operations.

Recent Developments

In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate the Company’s midstream business, including the ownership and control of QEP Field Services, which include its general and limited partner interests in QEP Midstream. We believe there is nothing in QEP’s announced strategy to separate its midstream business that precludes QEP Field Services from offering us acquisition opportunities to purchase additional midstream assets from it or to jointly pursue midstream acquisitions with it prior to or subsequent to the separation. Further, we do not believe QEP’s acreage dedicated to our assets will be changed significantly due to the separation and we believe these acreage dedications will continue to provide us a platform for future organic growth from our existing assets.

On January 23, 2014, the Partnership declared its quarterly cash distribution totaling $14.2 million, or $0.26 per unit, for the fourth quarter of 2013. This distribution was paid on February 14, 2014, to unitholders of record on the close of business on February 4, 2014.

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

We generally do not take title to the oil and natural gas that we gather or transport. We provide substantially all of our gathering services pursuant to fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Under these arrangements, we are paid a fixed or margin-based fee with respect to the volume of the oil and natural gas we gather. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. In addition to our fee-based gathering services, for the period from August 14, 2013, through December 31, 2013, approximately 4% of our Partnership's revenue was generated through the sale of condensate volumes that we collect on our gathering systems. Although the Partnership has entered into a fixed price condensate sales agreement with QEP, we still have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of oil and natural gas available for gathering by our systems. Refer to Item 7A of Part II of this Annual Report on Form 10-K for a discussion of our exposure to commodity price risk through our condensate recovery and sales.


58


We have secured significant acreage dedications from several of our largest customers, including QEP. We believe that drilling activity on acreage dedicated to us should, in the aggregate, maintain or increase our existing throughput levels and offset the natural production declines of the wells currently connected to our gathering systems. Specifically, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and are 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 in which our gathering systems currently exist or could be expanded to connect to additional wells.

We provide a portion of our gathering and transportation services on our Three Rivers and Williston gathering systems through firm contracts with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall.

How We Evaluate Our Business

Our management uses a variety of financial and operating metrics to analyze our performance including: (i) throughput volumes; (ii) gathering expenses; (iii) maintenance and expansion capital expenditures; (iv) Adjusted EBITDA; and (v) Distributable Cash Flow. Both Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures.

Throughput volumes

The amount of revenue we generate depends primarily on the volumes of natural gas and crude oil that we gather for our customers. The volumes transported on our gathering pipelines are driven by upstream development drilling activity and production volumes from the wells connected to our gathering pipelines. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas and natural gas liquids (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 positively correlate with long-term trends in natural gas, oil and NGL prices.

Gathering expenses

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

Maintenance and Expansion Capital Expenditures

We define maintenance capital expenditures as those that will enable us to maintain our operating capacity or operating income over the long term and expansion capital expenditures as those that we expect will increase our operating capacity or operating income over the long-term. We schedule our ongoing, routine operating and maintenance expenditures on our gathering systems throughout the calendar year to avoid significant variability in our cash flows and maintain safe operations. There is typically some seasonality in our expenditures as we generally reduce routine maintenance in the winter months due to weather conditions. We actively seek new opportunities to add throughput to our systems by expanding the geographic areas covered by our gathering systems, connecting new wells to the systems and installing additional compression. We analyze the expected return on expansion expenditures and attempt to negotiate terms in our gathering agreements that ensure we will receive an acceptable rate of return on those expenditures.

Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We define Adjusted EBITDA as net income attributable to the Partnership or the Predecessor before depreciation and amortization, interest and other income, interest expense, gains and losses from asset sales, deferred revenue associated with minimum volume commitment payments, and certain other non-cash and/or non-recurring items. We define Distributable Cash Flow as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity method investments and non-controlling interests, and other non-cash expenses. Distributable Cash Flow does not reflect changes in working capital balances.


59


Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:
•
our operating performance as compared to those of other companies in the midstream sector, without regard to financing methods, historical cost basis or capital structure;
•
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
•
our ability to incur and service debt and fund capital expenditures; and
•
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, respectively. Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to net income attributable to the Partnership or the Predecessor, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow excludes some, but not all, items that affect net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, and these measures may vary among other companies. As a result, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

General Trends and Outlook

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

Oil and natural gas supply and demand

Our gathering operations are primarily dependent upon oil and natural gas production from the upstream sector in our areas of operation. The decline in natural gas prices over the prior years 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 of the natural gas, that we believe will offset the production and drilling declines seen in other areas. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in oil and natural gas prices could affect production rates over time and levels of investment by QEP and third parties in exploration for and development of new oil and natural gas reserves. During 2012, QEP operated six drilling rigs in the Pinedale Field, but in 2013 QEP reduced the number of operated rigs to four and continues to operate with four rigs. Although the rig count in 2013 was lower than the rig count in 2012, QEP completed approximately 111 gross wells during the year ended December 31, 2013, compared to 102 gross wells for the year ended December 31, 2012, as a result of the inventory of wells drilled but not yet completed at the beginning of the year and more efficient drilling and completion operations. QEP expects to complete approximately the same number of wells for the year ended December 31, 2014, as in 2013 and 2012.

Rising operating costs and inflation

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

Impact of interest rates

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


60


Regulatory compliance

The regulation of oil and natural gas transportation activities by the FERC, and other federal and state regulatory agencies, including the DOT, has a significant impact on our business. For example, the Pipeline and Hazardous Materials Safety Administration office of the DOT has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation of oil and natural gas. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems.

Acquisition opportunities

We may acquire additional midstream assets from QEP Field Services or third parties. If QEP Field Services chooses to pursue midstream asset sales, it is under no contractual obligation to offer assets or business opportunities to us. We are not currently a party to any written agreements to purchase additional midstream assets from QEP Field Services. In addition, we may pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or QEP's existing asset base. In addition to our existing areas of operation, we may diversify our business through acquisition and greenfield development opportunities in geographic regions where neither QEP nor we currently operate. We believe that we will be well-positioned to acquire midstream assets from third parties should opportunities arise. If we do not make acquisitions from QEP Field Services or third parties on economically acceptable terms, our future growth will be limited. Furthermore acquisitions we do make could reduce, rather than increase, our cash generated from operations on a per-unit basis.
Factors Affecting the Comparability of Our Financial Results

The Partnership's results of operations subsequent to the IPO will not be comparable to the Predecessor's historical results of operations for the reasons described below.

Assets not included in the Partnership

The Predecessor's results of operations prior to the IPO include revenues and expenses relating to QEP Field Services' ownership of the Uinta Basin Gathering System and general support equipment. These assets were retained by QEP Field Services and were not contributed to the Partnership in connection with the IPO.

General and administrative expenses

For the period from January 1, 2013, through August 13, 2013, the Predecessor incurred $13.6 million in general and administrative expenses. The Predecessor's general and administrative expenses included costs allocated by QEP. These costs were reimbursed and related 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) compensation, share-based compensation, benefits and pension and post-retirement costs. General and administrative expenses were allocated to the Predecessor based on its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable.

Subsequent to the IPO, in accordance with the Omnibus Agreement, QEP charges the Partnership a combination of direct and allocated charges for administrative and operational services. The annual fee is currently set at approximately $13.8 million. For the period from August 14, 2013, through December 31, 2013, the Partnership incurred $5.5 million of such administrative and operational services expenses, of which $4.6 million was charged by QEP as an administrative fee.

We anticipate incurring approximately $2.5 million of incremental general and administrative expenses annually attributable to operating as a publicly traded partnership, such as expenses associated with annual, quarterly and current reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; outside director fees; and director and officer insurance expenses. These incremental general and administrative expenses are not reflected in our historical consolidated financial statements prior to the IPO. The Partnership's general and administrative expense will also include compensation expense associated with the LTIP.


61


Working capital

The impact of all affiliated transactions of the Predecessor historically has been net settled within QEP's consolidated financial statements, because these transactions related to QEP and were funded by QEP's working capital. Third-party transactions were also funded by QEP's working capital. Subsequent to the IPO, all affiliate and third-party transactions are funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

Interest expense

Prior to the IPO, we incurred interest expense on intercompany notes payable to QEP that was allocated to us. These balances were repaid with a portion of the proceeds from the IPO; therefore, interest expense attributable to these balances and reflected in our historical consolidated financial statements will not be incurred in the future. Upon the closing of the IPO, we entered into a $500.0 million revolving credit facility agreement, which contains customary short-term interest rates and a commitment fee on the unused portion of the facility.

Cash distributions to unitholders

The Partnership expects to make quarterly cash distributions to our unitholders and our General Partner, at a minimum, of our quarterly distribution amount of $0.25 per unit ($1.00 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our General Partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including borrowings under our credit facility and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and advances under intercompany loans from QEP to satisfy our capital expenditure requirements.

62


Results of Operations
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
 
(in millions, except per unit information)
Revenues
 
 
 
 
 
 
 
 
Gathering and transportation
 
$
46.1

 
$
92.9

 
$
151.3

 
$
140.4

Condensate sales
 
2.0

 
7.4

 
10.9

 
15.5

Total revenues
 
48.1

 
100.3

 
162.2

 
155.9

Operating expenses
 

 


 

 

Gathering expenses
 
9.8

 
19.7

 
29.9

 
27.7

General and administrative
 
5.5

 
13.6

 
17.0

 
15.3

Taxes other than income taxes
 
0.8

 
1.3

 
3.1

 
2.8

Depreciation and amortization
 
11.7

 
25.0

 
39.8

 
38.3

Total operating expenses
 
27.8

 
59.6

 
89.8

 
84.1

Net loss from property sales
 
—

 
(0.5
)
 
—

 
—

Operating income
 
20.3

 
40.2

 
72.4

 
71.8

Other income
 
—

 
—

 
0.1

 
0.1

Income from unconsolidated affiliates
 
1.2

 
3.8

 
7.2

 
4.4

Interest expense
 
(0.9
)
 
(2.6
)
 
(8.7
)
 
(12.8
)
Net income
 
20.6

 
41.4

 
71.0

 
63.5

Net income attributable to noncontrolling interest
 
(1.5
)
 
(2.5
)
 
(3.7
)
 
(3.2
)
Net income attributable to QEP Midstream or Predecessor
 
$
19.1

 
$
38.9

 
$
67.3

 
$
60.3

Operating Statistics
 
 
 
 
 
 
 
 
Natural gas throughput in millions of MMBtu
 
 
 
 
 
 
 
 
Gathering and transportation
 
115.0

 
230.9

 
387.8

 
384.7

Equity interest(1)
 
7.1

 
13.4

 
27.5

 
34.4

Total natural gas throughput
 
122.1

 
244.3

 
415.3

 
419.1

Throughput attributable to noncontrolling interests(2)
 
(3.6
)
 
(6.7
)
 
(12.1
)
 
(14.3
)
Total throughput attributable to QEP Midstream or Predecessor
 
118.5

 
237.6

 
403.2

 
404.8

Crude oil and condensate gathering system throughput volumes (MBbls)
 
1,743.2

 
3,243.1

 
5,297.4

 
4,105.4

Water gathering volumes (MBbls)
 
1,765.3

 
2,450.3

 
3,998.4

 
3,536.6

Condensate sales volumes (MBbls)
 
23.4

 
90.6

 
125.8

 
177.4

Price
 

 


 

 

Average gas gathering and transportation fee (per MMBtu)
 
$
0.34

 
$
0.35

 
$
0.34

 
$
0.30

Average oil and condensate gathering fee (per barrel)
 
$
2.13

 
$
2.44

 
$
2.31

 
$
1.89

Average water gathering fee (per barrel)
 
$
1.85

 
$
1.82

 
$
1.84

 
$
1.86

Average condensate sale price (per barrel)
 
$
85.25

 
$
81.63

 
$
86.06

 
$
87.21

Non-GAAP Measures
 

 


 

 

Adjusted EBITDA(3)
 
$
30.7

 
$
65.4

 
$
112.9

 
$
109.6

Distributable Cash Flow(3)
 
26.7

 
 
 
 
 
 
            
(1)
Includes our 50% share of gross volumes from Three Rivers Gathering and the Predecessor's 38% share of gross volumes from Uintah Basin Field Services.
(2)
Includes the 22% noncontrolling interest in Rendezvous Gas.
(3) 
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures previously defined and reconciled in Item 6. Selected Financial Data within this document.

63


Successor Results of Operations

On August 14, 2013, the Partnership completed its IPO. Prior to the closing of the IPO, QEP Field Services and the General Partner contributed, as capital contributions, $407.8 million of net assets representing their limited liability company interest in the Operating Company. The contribution of QEP Field Services’ and the General Partners’ limited liability interest in the Operating Company to the Partnership was valued using the carryover book value of the Operating Company, as the transaction is a transfer of assets between entities under common control. The Partnership’s assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines and exclude the Uinta Basin Gathering System, which was retained by QEP Field Services. The Partnership’s (Successor’s) operating results for the period from August 14, 2013, through December 31, 2013, are presented below.

Period From August 14, 2013, through December 31, 2013

Revenue

Gathering and transportation. Gathering and transportation revenues were $46.1 million for the period from August 14, 2013, through December 31, 2013. Natural gas gathering and transportation revenue was $39.1 million with throughput of 118.5 million MMBtu and an average gas gathering and transportation fee of $0.34 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System which contributed 82.6 million MMBtu related to production at QEP's Pinedale operations and our Vermillion Gathering System with throughput of 15.9 million MMBtu.

Crude oil and condensate gathering revenue was $3.7 million for the period from August 14, 2013, through December 31, 2013, as a result of an average gathering fee of $2.13 per barrel and throughput of 1,743.2 Mbbls of which 1,370.5 Mbbls was attributable to our Green River Gathering System and 372.7 Mbbls was attributable to our Williston Gathering System. Water gathering revenue consisted of $3.3 million for the period from August 14, 2013, through December 31, 2013, from throughput of 1,765.3 Mbbls and an average fee of $1.85 per barrel at our Green River Gathering System.

Condensate sales.    Revenue from condensate sales was $2.0 million for the period from August 14, 2013, through December 31, 2013, from sales volumes of 23.4 Mbbls at a price of $85.25 per barrel as a result of our fixed price sales agreement with QEP Field Services, which was effective on August 14, 2013.

Operating Expenses

Gathering expenses.    Gathering expenses were $9.8 million for the period from August 14, 2013, through December 31, 2013, of which the majority of the expenses were incurred on our Green River and Vermillion gathering systems.

General and administrative.    General and administrative expenses were $5.5 million for the period from August 14, 2013, through December 31, 2013, consisting of $4.6 million from charges under the Omnibus Agreement, $0.4 million for equity-based compensation expense and the remainder related to other expenses related to operating as a publicly traded partnership.

Taxes other than income taxes.    Taxes other than income taxes were $0.8 million for the period from August 14, 2013, through December 31, 2013, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization.    Depreciation and amortization expenses were $11.7 million for the period from August 14, 2013, through December 31, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates.    Income from unconsolidated affiliates was $1.2 million for the period from August 14, 2013, through December 31, 2013 related to income from Three Rivers Gathering.

Interest expense.    Interest expense was $0.9 million for the period from August 14, 2013, through December 31, 2013, related to commitment fees paid on the unused portion of the Credit Facility. There were no borrowings under the Credit Facility during the period.


64


Predecessor Results of Operations

The Predecessor financial statements were prepared in connection with the IPO. The Predecessor consists of all of the Partnership’s gathering assets as well as the Uinta Basin Gathering System. The Uinta Basin Gathering System was retained by QEP Field Services and was not part of the assets conveyed to the Partnership. Under "Supplemental Disclosures" below, we have included pro forma historical data and analysis limited to only the properties conveyed to us in connection with the IPO, as we believe such data is more useful to the reader to better understand trends in operations.

Period From January 1, 2013, through August 13, 2013 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $92.9 million for the period from January 1, 2013, through August 13, 2013. Natural gas gathering and transportation revenue was $80.5 million with throughput of 237.6 million MMBtu and an average gas gathering and transportation fee of $0.35 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 124.0 million MMBtu of throughput as a result of increased production at QEP's Pinedale operations; the Predecessor's Uinta Basin Gathering System, with throughput of 45.8 million MMBtu; and our Vermillion Gathering System, with throughput of 30.2 million MMBtu.

Crude oil and condensate gathering revenue was $7.9 million for the period from January 1, 2013, through August 13, 2013, as a result of an average gathering fee of $2.44 per barrel and throughput of 3,243.1 Mbbls of which 2,490.0 Mbbls was attributable to our Green River Gathering System and 753.1 Mbbls was attributable to our Williston Gathering System. Water gathering revenue consisted of $4.5 million for the period from January 1, 2013, through August 13, 2013, from throughput of 2,450.3 Mbbls and an average fee of $1.82 per barrel at our Green River Gathering System.

Condensate sales.    Revenue from condensate sales was $7.4 million for the period from January 1, 2013, through August 13, 2013, from sales volumes of 90.6 Mbbls at a price of $81.63 per barrel primarily attributable to the Predecessor's Green River, Uinta Basin and Vermillion gathering systems.

Operating Expenses

Gathering expenses.    Gathering expenses were $19.7 million for the period from January 1, 2013, through August 13, 2013, of which the majority of the expenses were incurred on the Predecessor's Green River, Uinta Basin and Vermillion gathering systems.

General and administrative.    General and administrative expenses were $13.6 million for the period from January 1, 2013, through August 13, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes.    Taxes other than income taxes were $1.3 million for the period from January 1, 2013, through August 13, 2013, primarily attributable to property tax expense on the Predecessor's gathering systems.

Depreciation and amortization.    Depreciation and amortization expenses were $25.0 million for the period from January 1, 2013, through August 13, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates.    Income from unconsolidated affiliates was $3.8 million for the period from January 1, 2013, through August 13, 2013. Income from Uintah Basin Field Services was $2.2 million and income from Three Rivers Gathering was $1.6 million.

Interest expense.    Interest expense was $2.6 million for the period from January 1, 2013, through August 13, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.


65


Year Ended December 31, 2012 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $151.3 million for the year ended December 31, 2012. Natural gas gathering and transportation revenue was $132.7 million with throughput of 403.2 million MMBtu and an average gas gathering and transportation fee of $0.34 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 201.7 million MMBtu of throughput; the Predecessor's Uinta Basin Gathering System, with throughput of 78.6 million MMBtu; and our Vermillion Gathering System, with throughput of 52.0 million MMBtu.

Crude oil and condensate revenue was $11.2 million for the year ended December 31, 2012, as a result of an average gathering fee of $2.31 per bbl and throughput of 5,297.4 Mbbls of which 4,286.3 Mbbls was attributable to our Green River Gathering System and 1,011.1 Mbbls was attributable to our Williston Gathering System. Water gathering revenue consisted of $7.4 million for the year ended December 31, 2012, from throughput of 3,998.4 Mbbls and an average fee of $1.84 per bbl at our Green River Gathering System.

Condensate sales.    Revenue from condensate sales was $10.9 million for the year ended December 31, 2012, from sales volumes of 125.8 Mbbls at a price of $86.06 per bbl primarily attributable to our Green River Gathering System.

Operating Expenses

Gathering expenses.    Gathering expenses were $29.9 million for the year ended December 31, 2012, of which the majority of the expenses were incurred on the Predecessor's Green River, Uinta Basin and Vermillion gathering systems.

General and administrative.    General and administrative expenses were $17.0 million for the year ended December 31, 2012, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes.    Taxes other than income taxes were $3.1 million for the year ended December 31, 2012, primarily attributable to property tax expense on the Predecessor's gathering systems.

Depreciation and amortization.    Depreciation and amortization expenses were $39.8 million for the year ended December 31, 2012, related to normal depreciation and accretion expenses recognized on the gathering systems in place.

Other Results Below Operating Income

Income from unconsolidated affiliates.    Income from unconsolidated affiliates was $7.2 million for the year ended December 31, 2012. Income from Uintah Basin Field Services was $3.7 million and income from Three Rivers Gathering was $3.5 million.

Interest expense.    Interest expense was $8.7 million for the year ended December 31, 2012, related to interest charged on the Predecessor's outstanding long-term debt with QEP throughout the period.

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

Revenue

Gathering and transportation.    Revenues increased $10.9 million, or 8%, in 2012 due to a $6.7 million increase in natural gas gathering revenues, a $3.4 million increase in crude oil and condensate gathering revenues, and a $0.8 million increase in water gathering revenues. Natural gas gathering revenues were higher in 2012 due to a 13% increase in average gathering fees per MMBtu, and a 3.1 million MMBtu increase in gathering volumes. The increase in the average gathering fee was due to a $1.2 million increase in compression revenues, and a $0.8 million increase in transportation revenues. Natural gas gathering volumes increased primarily due to a 14.6 million MMBtu increase in Green River System throughput related to QEP Pinedale drilling and a 2.7 million MMBtu increase in Vermillion System throughput from increased drilling activity. These throughput increases were offset by a 4.5 million MMBtu decrease in the Uinta Basin Gathering System throughput due to a decline of drilling activity in the area.

Crude oil and condensate gathering revenues increased in 2012 due to a 29% increase in throughput volumes and a 22% increase in the average gathering fee. Oil and condensate gathering volumes increased 620.1 MBbls on our Williston Gathering

66


System from increased drilling by QEP and 571.9 MBbls on our Green River System due to additional unaffiliated volumes. The increase in the average gathering fee was primarily due to an increase of barrels into the system in which we receive a higher fee for transportation of those barrels.

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

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

Operating Expenses

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

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

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

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

Other Results Below Operating Income

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

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


67


Liquidity and Capital Resources

Prior to the IPO, our sources of liquidity included 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 IPO, we maintain our own bank accounts and sources of liquidity and continue to utilize QEP's cash management expertise. Our ongoing sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures include cash generated from operations, borrowings under our Credit Facility, and access to debt and equity markets. We may also consider the use of alternative financing strategies such as entering into additional joint venture arrangements or selling non-strategic assets. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Cash Flow

The following table and discussion presents a summary of our net cash provided by operating activities, investing activities and financing activities for the periods indicated.
 
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
 
 
 
Operating activities
 
$
31.6

 
$
90.9

 
$
107.0

 
$
97.5

Investing activities
 
(13.7
)
 
(8.5
)
 
(43.4
)
 
(28.5
)
Financing activities
 
—

 
(82.7
)
 
(64.7
)
 
(68.0
)

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:
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
 
(in millions)
Net income
 
$
20.6

 
$
41.4

 
$
71.0

 
$
63.5

Non-cash adjustments to net income
 
12.4

 
26.6

 
40.4

 
41.6

Changes in operating assets and liabilities
 
(1.4
)
 
22.9

 
(4.4
)
 
(7.6
)
Net cash provided from operating activities
 
$
31.6

 
$
90.9

 
$
107.0

 
$
97.5





68


Investing Activities. Our Predecessor's historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. The Partnership's capital expenditures were funded from cash flow generated from operations. Our historical capital expenditures are presented in the following table:
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor
 
Predecessor
 
Predecessor
 
Predecessor
 
 
 
 
(in millions)
 
 
Total accrual capital expenditures
 
$
18.5

 
$
7.5

 
$
42.4

 
$
(27.1
)
Change in accruals and non-cash items
 
(4.3
)
 
1.6

 
1.3

 
(1.5
)
Total cash capital expenditures
 
$
14.2

 
$
9.1

 
$
43.7


$
(28.6
)

Financing Activities. As a result of the IPO, for the period from August 14, 2013, through December 31, 2013, we had net proceeds of $449.6 million which were used to repay long-term debt to QEP of $95.5 million, pay revolving credit origination fees of $3.0 million and make a cash distribution to QEP for $351.1 million. Additionally, the Partnership received $9.6 million from QEP under the indemnification provisions of the Omnibus Agreement for capital expenditures incurred by the Partnership for a pipeline repair project. Lastly, the Partnership paid distributions of $7.1 million, or $0.13 per unit, to public common unitholders, and $2.2 million to owners of non-controlling interests in our assets.

For the period from January 1, 2013, through August 13, 2013, the Predecessor's cash used in financing activities primarily consisted of $66.4 million in repayments of long-term debt to QEP compared to $43.6 million of cash used in financing activities of the Predecessor for the year ended December 31, 2012. In addition, our Predecessor made distributions to QEP of $12.2 million and distributions to its noncontrolling interest in Rendezvous Gas of $4.1 million for the period from January 1, 2013, through August 13, 2013.

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

Capital Requirements

The oil and natural gas gathering segment of the midstream energy business is capital-intensive, requiring investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either maintenance or expansion.
•
Maintenance capital expenditures are those cash expenditures that will enable us to maintain our operating capacity or operating income over the long term. Maintenance capital expenditures include well connections or the replacement, improvement or expansion of existing capital assets, including the construction or development of new capital assets, to replace expected reductions in hydrocarbons available for gathering handled by our gathering systems. Other examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines and compression equipment and to maintain equipment reliability, integrity and safety, as well as to address environmental laws and regulations.
•
Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include the acquisition of assets from QEP Field Services or third parties and the construction or development of additional pipeline capacity, well connections or compression, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is disposed of or abandoned.


69


Capital expenditures totaled $18.5 million for the Partnership during the Post-IPO Period, which includes expansion capital of $5.4 million and maintenance capital of $13.1 million. Maintenance capital expenditures of $13.1 million include $9.6 million related to a condensate pipeline repair and replacement project. The Partnership was reimbursed by QEP for these costs pursuant to an indemnification provision in the Omnibus Agreement executed in connection with the closing of the IPO. The remaining maintenance capital expenditures of $3.5 million relate to several compressor overhauls and line looping projects intended to improve efficiency and increase flexibility on the Vermillion and Green River gathering systems. Expansion capital expenditures of $5.4 million related primarily to a compressor replacement project on the Vermillion Gathering System and reimbursable well connects on the Williston Gathering System.

We expect our gross capital expenditures to range from $18.0 million to $22.0 million for the year ending December 31, 2014. This amount includes approximately $10.0 million to $12.0 million of maintenance capital and approximately $8.0 million to $10.0 million of expansion capital. Maintenance capital spending includes compressor maintenance projects primarily in the Green River and Vermillion areas, well connects in the Green River area, and gathering system modifications in the Green River area. Expansion capital spending includes expansion of the Vermillion Gathering System and reimbursable well connects in the Williston Gathering System. Capital spending may vary significantly from period to period based on the investment opportunities available to us and the timing of large maintenance items. We expect to fund the 2014 capital expenditures with cash flow generated from operations and borrowings under our Credit Facility.

Distributions

For the period from August 14, 2013, through December 31, 2013, the Partnership paid distributions of $7.1 million related to the third quarter of 2013 distribution. Further, on January 23, 2014, the Partnership declared its quarterly cash distribution totaling $14.2 million, or $0.26 per unit for the fourth quarter of 2013. This distribution was paid on February 14, 2014, to unitholders of record on the close of business on February 4, 2014. No distributions related to the General Partner's incentive distribution rights were declared.

At a minimum, we plan to pay a quarterly distribution of $0.25 per unit, which equates to $13.6 million per full calendar quarter, or $54.5 million per year, based on the number of common, subordinated and general partner units outstanding. Although our Partnership Agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit. Refer to Item 5 of Part II of this Annual Report on Form 10-K for additional information.

Credit Facility

In connection with the IPO, we entered into the Credit Facility, a $500.0 million senior secured revolving credit agreement, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders with a maturity date of August 14, 2018. The Credit Facility contains an accordion provision that allows the amount of the facility to be increased to $750 million with the agreement of the lenders. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for transactions of this nature.

The Credit Facility contains various covenants and restrictive provisions and also requires maintenance of a total leverage ratio of not more than 5.00 to 1.00 (or, after the consummation of a qualified senior notes offering, not more than 5.50 to 1.00), an interest coverage ratio of not less than 2.50 to 1.00 and after consummation of a qualified senior notes offering, a senior secured leverage ratio of not more than 3.50 to 1.00.

Loans under the Credit Facility (other than swing line loans discussed below) will bear interest at the Partnership's option at a variable rate per annum equal to either:
•
a base rate, which will be the highest of (i) the administrative agent’s prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or
•
LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio.
•
Swing line loans will bear interest at (i) the federal funds rate plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidate leverage ratio or (ii) a rate to be established as provided in the Credit Facility, as selected by the borrower and specified in the swing line loan notice delivered by the borrower in connection with the loan.

70



There were no borrowings under the Credit Facility during the period ended December 31, 2013. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.325% to 0.500% per annum. For the period from August 14, 2013, through December 31, 2013, the Partnership incurred $0.7 million of commitment fees.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include companies that may react differently to changing conditions. Our principal customers are QEP and QGC, who account for approximately 68% and 16% respectively, of the Partnership's total revenues. We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including QEP and QGC. Consequently, we are subject to the risk of non-payment or late payment by QEP and QGC of gathering fees, and this risk is greater than it would be with a broader customer base with a similar credit profile.

Our gathering agreement with QGC is the subject of ongoing litigation, in which QGC is disputing the calculation of the gathering rate and has been netting the disputed amount from its monthly payment of gathering fees to QEP Field Services and the Partnership since the second quarter of 2012. As of December 31, 2013, the Partnership has deferred revenue of $8.5 million related to the QGC disputed amount. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement. For more information regarding the litigation with QGC, refer to Note 9 - Commitments and Contingencies, in Item 8 and Legal Proceedings in Item 3, Part I of this Annual Report on Form 10-K.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on our principal customers, and in particular QEP, for our revenues. If QEP becomes unable to perform under the terms of our gathering agreements, or the Omnibus Agreement, it may significantly reduce our ability to make distributions to our unitholders.

Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, we enter into a variety of contractual cash obligations and other commitments. The following table summarizes the significant contractual cash obligations as of December 31, 2013:
 
 
Payments Due by Year
 
 
Total
 
2014
 
2015
 
2016
 
2017
 
2018
 
After 2018
 
 
(in millions)
Asset retirement obligations(1)
 
13.3

 
—

 
—

 
—

 
—

 
—

 
$
13.3

Total
 
$
13.3

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
13.3

            
(1) 
These future obligations are discounted estimates of future expenditures based on expected settlement dates.

Related Parties

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of December 31, 2013, QEP Field Services owns 3,701,750 common units and 26,705,000 subordinated units representing a 55.8% limited partner interest in us. In addition, our General Partner owns 1,090,117 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEP Field Services and QEP are considered to be related party transactions because our General Partner and its affiliates own more than 5% of our equity interests.


71


In connection with the IPO, QEP Midstream entered into various agreements with QEP Field Services, QEP and our General Partner including, but not limited to, the following: the Omnibus Agreement, the Partnership Agreement, gathering and transportation agreements, a fixed priced condensate purchase agreement, operating agreements and other service agreements. For the period August 14, 2013 to December 31, 2013, approximately 68% of our revenue came from QEP. Prior to the IPO, the Predecessor had other agreements in place with QEP resulting in related party transactions. For the period from January 1, 2013, through August 13, 2013, QEP accounted for 55% of the Predecessor's total revenue. 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. Refer to Note 4 - Related Party Transactions, in Item 8 of Part II of this Annual Report on Form 10-K for additional information on related party transactions for the pre and Post-IPO Periods.

Critical Accounting Policies and Estimates

The following discussion relates to the critical accounting policies and estimates for both QEP Midstream and our Predecessor. All references to "QEP Midstream", "we", "our", or "us" is applicable to both QEP Midstream and our Predecessor. Our consolidated financial statements are prepared in accordance with GAAP. The preparation of consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. The following accounting policies may involve a higher degree of complexity and judgment on the part of management.

Revenue Recognition

QEP Midstream provides natural gas gathering and transportation services, primarily under fee-based contracts. Under these arrangements, we receive a fee or fees for one or more of the following services: firm and interruptible gathering or transmission of natural gas, crude oil, condensate, and water. The revenue we earn from these arrangements is generally directly related to the volume of natural gas, crude oil, or water that flows through the our systems and is not directly dependent on commodity prices. Revenue for these agreements is generally recognized at the time the service is performed. In certain of these contracts, the agreement provides for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms. In addition, under certain of these gathering agreements, we retain and sell condensate, which falls out of the natural gas stream during the gathering process. We recognize revenue from condensate sales upon transfer of title. The Partnership has deferred revenue of which a portion will be recognized as revenue pursuant to contractual terms with the remaining being recognized based on the outcome of certain litigation (refer to Note 9 - Commitments and Contingencies, in Item 8 of Part II of this Annual Report on Form 10-K).

Property, Plant and Equipment

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

Capitalization and Depreciation of Assets

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

Impairment of Long-lived Assets

QEP Midstream evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset or a change in management’s intent to utilize the asset. There were no long-lived asset impairments recognized during 2013, 2012 or 2011.


72


Asset Retirement Obligations

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

Environmental Obligations

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

Recent Accounting Developments

See Recent Accounting Developments in Note 2 - Summary of Significant Accounting Policies, in Item 8 of Part II of this Annual Report on Form 10-K.

73


Supplemental Disclosures

As previously discussed, certain information contained in this report relates to periods that ended prior to the completion of the IPO, and prior to the effective dates of the agreements discussed herein. Consequently, the results discussed above include results for both the properties conveyed to the Partnership in connection with the IPO and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the IPO is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations.

The following pro forma financial data is for informational purposes only and was derived from the Predecessor financial information removing the results of the assets retained by the Predecessor, consisting of the Uinta Basin Gathering System and general support equipment. Further, management does not believe that the financial data is necessarily comparable to the financial data reported by the Partnership for periods subsequent to the IPO, indicative of future results of the Partnership, or reflective of other transactions that resulted in the capitalization and start-up of the Partnership. Refer to "Factors Affecting the Comparability of Our Financial Results" above for a description of the significant factors affecting the comparability of the Predecessor's historical results of operations and those of the Partnership subsequent to the IPO.
QEP Midstream Partners, LP
Unaudited Pro Forma Financial Data

 

Year Ended December 31,

Change
 

2013

2012

2011

2013 vs. 2012

2012 vs. 2011
 
(in millions, except operating and per unit amounts)
Revenues










Gathering and transportation

$
119.0


$
119.0


109.0


$
—


$
10.0

Condensate sales

7.6


8.5


11.7


(0.9
)

(3.2
)
Total revenues

$
126.6


$
127.5


$
120.7


$
(0.9
)

$
6.8

Operating expenses












Gathering expenses

$
24.0


$
21.1


$
19.1


$
2.9


$
2.0














Operating Statistics












Natural gas throughput in millions of MMBtu












Gathering and transportation

300.2


309.2


301.6


(9.0
)

7.6

Equity interest(1)

19.5


25.7


31.8


(6.2
)

(6.1
)
Total natural gas throughput

319.7


334.9


333.4


(15.2
)

1.5

Throughput attributable to noncontrolling interests(2)

(10.3
)

(12.1
)

(14.3
)

1.8


2.2

Total throughput attributable to QEP Midstream or Predecessor

309.4


322.8


319.1


(13.4
)

3.7

Crude oil and condensate gathering system throughput volumes (MBbls)

4,986.3


5,297.4


4,105.4


(311.1
)

1,192.0

Water gathering volumes (MBbls)

4,215.6


3,998.4


3,536.6


217.2


461.8

Condensate sales volumes (MBbls)

92.2


98.8


130.7


(6.6
)

(31.9
)
Price












Average gas gathering and transportation fee (per MMBtu)

$
0.33


$
0.32


$
0.28


$
0.01


$
0.04

Average oil and condensate gathering fee (per barrel)

$
2.49


$
2.31


$
1.89


$
0.18


$
0.42

Average water gathering fee (per barrel)

$
1.83


$
1.84


$
1.86


$
(0.01
)

$
(0.02
)
Average condensate sale price (per barrel)

$
82.67


$
86.43


$
89.33


$
(3.76
)

$
(2.90
)
            
(1)
Includes our 50% share of gross volumes from Three Rivers Gathering.
(2)
Includes the 22% noncontrolling interest in Rendezvous Gas.


74


Year Ended December 31, 2013, compared to Year Ended December 31, 2012 - Pro Forma

Revenue

Gathering and transportation. Gathering and transportation revenues were flat for the year ended December 31, 2013, compared to the year ended December 31, 2012, due to a $0.3 million decrease in natural gas gathering revenue, offset by a $0.3 million increase in water gathering revenue. The decrease in natural gas gathering revenue was due to a 4% decrease in volumes partially offset by a 3% increase in average gathering rate. The decrease in natural gas volumes was a result of a decrease in the Vermillion and Rendezvous gathering systems throughput from declines in upstream drilling activity partially offset by an increase in natural gas gathering volumes in our Green River Gathering and Williston Gathering systems due to increases in QEP's production in these areas.

Water gathering revenue was $0.3 million higher for the year ended December 31, 2013, compared to the year ended December 31, 2012, due to increases in the Green River Gathering System from upstream drilling and completion activity. Crude oil and condensate gathering revenue was flat due to a 8% increase in the average rate offset by a 6% decrease in third party volumes due to lower throughput in the Green River Gathering System.

Condensate sales.    Revenues from condensate sales decreased $0.9 million, or 11% for the year ended December 31, 2013, compared to the year ended December 31, 2012, due to a 7% decrease in condensate sales volumes and a 4% decrease in average condensate sales price. The decrease in volumes is primarily attributable to a decrease in our Green River Gathering System due to a new contract with QEP in mid-2012, which allows QEP to retain condensate volumes that accumulate in the gathering system. The decrease in price is due to the fixed-price condensate sales agreement with QEP that we entered into on August 14, 2013.

Operating Expenses

Gathering expenses.    Gathering expenses increased $2.9 million, or 14%, for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due an increase in labor and benefits costs associated with the contributed properties.

Year Ended December 31, 2012, compared to Year Ended December 31, 2011 - Pro Forma

Revenue

Gathering and transportation. Gathering and transportation revenues were $10.0 million higher for the year ended December 31, 2012, compared to the year ended December 31, 2011, due to a $5.8 million increase in natural gas gathering revenue, a $3.4 million increase in crude oil and condensate revenue, and a $0.8 million increase in water gathering revenue. The increase in natural gas gathering revenue was due to a 1% increase in volumes and a 14% increase in average gathering rate. The increase in natural gas volumes was a result of an increase in Green River and Vermillion gathering systems due to an increase in QEP's operated production in these areas.

Water gathering revenue was 12% higher for the year ended December 31, 2012, compared to the year ended December 31, 2011, due to increases in the Green River Gathering System. Crude oil and condensate gathering revenue was 44% higher due to a 22% increase in the average rate and a 29% increase in volumes due to higher throughput in the Green River and Williston gathering systems.

Condensate sales.    Revenues from condensate sales decreased $3.2 million, or 27%, for the year ended December 31, 2012, compared to the year ended December 31, 2011, due to a decrease in condensate sales volumes of 24% and a 3% decrease in average condensate sales price. The decrease in volumes is primarily attributable to a decrease in the Vermillion Gathering System throughput from declines in upstream drilling activity and a decrease in our Green River Gathering System due to a new contract with QEP in mid-2012, which allows QEP to retain condensate volumes that accumulate in the gathering system.

Operating Expenses

Gathering expenses.    Gathering expenses increased $2.0 million, or 10%, for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due an increase in labor and benefits costs associated with the contributed properties.


75


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Prior to the IPO, our Predecessor's interest expense was an allocation of QEP Field Services' interest expense on debt which consisted of two promissory notes between QEP Field Services and QEP, each with a fixed rate of 6.0%, which were not subject to interest rate movements. The Partnership's new Credit Facility contains a variable interest rate that exposes us to volatility in interest rates. However, at December 31, 2013, we did not have any debt outstanding under the Credit Facility and therefore we did not have any debt subject to floating interest rates.

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenues is dependent upon the price received for the condensate. Condensate historically sells at a price representing a slight discount to the price of oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of revenues generated under these arrangements compared to our overall revenues. Historically, we have not entered into commodity derivative instruments because of the minimal impact on our revenues, however, in conjunction with the IPO, the Partnership entered into a fixed price condensate purchase agreement with QEP, which requires us to sell and QEP to purchase all of the condensate volumes collected on our gathering systems at a fixed price of $85.25 per barrel of product over a primary term of five years. In addition, we expect to utilize risk management tools to minimize future commodity price risk that could be associated with assets we may acquire or contracts we may enter into in the future.


76


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Financial Statements:
 
 
Page
Reports of Independent Registered Public Accounting Firm as of December 31, 2013 and 2012, and for the years ended December 31, 2013, 2012, and 2011
Consolidated Statements of Operations for the years ended December 31, 2013, 2012, and 2011
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statement of Cash Flows for the years ended December 31, 2013, 2012, and 2011
Consolidated Statement of Equity - Successor, for the period from inception to December 31, 2013
Consolidated Statement of Equity - Predecessor, for the periods from December 31, 2010 to August 13, 2013
Notes Accompanying the Consolidated Financial Statements
 
 
 
Financial Statement Schedule:
 
 
Valuation and Qualifying Accounts for the years ended December 31, 2013, 2012, and 2011
 
 
 

All other schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or Notes thereto.

77


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Partners of QEP Midstream Partners, LP:

In our opinion, the accompanying consolidated balance sheet as of December 31, 2013 and the related consolidated statements of income, equity, and cash flows for the period from August 14, 2013 to December 31, 2013 present fairly, in all material respects, the financial position of QEP Midstream Partners, LP at December 31, 2013, and the results of its operations and its cash flows for the period from August 14, 2013 to December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion the financial statement schedule for the period from August 14, 2013 to December 31, 2013 appearing under Item 15(c) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), which 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 audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 20, 2014

78



Report of Independent Registered Public Accounting Firm


To the Board of Directors and Partners of QEP Midstream Partners, LP:

In our opinion, the accompanying consolidated balance sheet as of December 31, 2012 and the related consolidated statements of income, equity, and cash flows for each of the two years in the period ended December 31, 2012 and for the period from January 1, 2013 to August 13, 2013 present fairly, in all material respects, the financial position of QEP Midstream Partners, LP Predecessor at December 31, 2012, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012 and for the period from January 1, 2013 to August 13, 2013, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2012 and for the period from January 1, 2013 to August 13, 2013 appearing under Item 15(c) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule 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), which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 20, 2014


79


QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
 
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 

Period From August 14, 2013, through December 31, 2013

Period From January 1, 2013, through August 13, 2013

Year Ended December 31, 2012
 
Year Ended December 31, 2011


Successor

Predecessor

Predecessor
 
Predecessor
 
(in millions, except per unit information)
Revenues






 
 
Gathering and transportation

$
46.1


$
92.9


$
151.3


$
140.4

Condensate sales

2.0


7.4


10.9


15.5

Total revenues

48.1


100.3


162.2


155.9

Operating expenses








Gathering

9.8


19.7


29.9


27.7

General and administrative

5.5


13.6


17.0


15.3

Taxes other than income taxes

0.8


1.3


3.1


2.8

Depreciation and amortization

11.7


25.0


39.8


38.3

Total operating expenses

27.8


59.6


89.8


84.1

Net loss from property sales

—


(0.5
)

—


—

Operating income

20.3


40.2


72.4


71.8

Other income
 
—

 
—

 
0.1

 
0.1

Income from unconsolidated affiliates

1.2


3.8


7.2


4.4

Interest expense

(0.9
)

(2.6
)

(8.7
)

(12.8
)
Net income

20.6


41.4


71.0


63.5

Net income attributable to noncontrolling interest

(1.5
)

(2.5
)

(3.7
)

(3.2
)
Net income attributable to QEP Midstream or Predecessor

$
19.1


$
38.9


$
67.3


$
60.3











 
 
Net income attributable to QEP Midstream per limited partner unit (basic and diluted):
 
 
 
 
 
 
 
 
Common units

$
0.35







 
 
Subordinated units

$
0.35







 
 










 
 
Weighted-average limited partner units outstanding (basic and diluted):
 
 
 
 
 
 
 
 
Common units

26.7







 
 
Subordinated units

26.7







 
 
  See notes accompanying the consolidated financial statements.



80


QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
 

December 31, 2013

December 31, 2012


Successor

Predecessor
 

(in millions)
ASSETS




Current assets:




Cash and cash equivalents

$
19.0


$
1.4

Accounts receivable, net

9.1


18.2

Accounts receivable from related party

25.5


24.9

Natural gas imbalance receivable

1.7


2.2

Other current assets

—


0.1

Total current assets

55.3


46.8

Property, plant and equipment, net

493.4


634.1

Investment in unconsolidated affiliates

27.8


40.7

Other noncurrent assets

3.4


3.8

Total assets

$
579.9


$
725.4

LIABILITIES




Current liabilities:




Accounts payable

$
6.6


$
6.3

Accounts payable to related party

9.0


3.7

Natural gas imbalance liability

1.7


2.2

Deferred revenue

9.6


0.3

Accrued compensation

—


1.7

Other current liabilities

0.2


1.3

Total current liabilities

27.1


15.5

Long-term debt (to related party at December 31, 2012)

—


131.1

Asset retirement obligation

13.3


16.3

Deferred revenue

11.9


10.2

Total long-term liabilities

25.2


157.6

Commitments and contingencies (see Note 9)




EQUITY




Limited partner common units - 26.7 million units issued and outstanding

411.7


—

Limited partner subordinated units - 26.7 million units issued and outstanding

68.0


—

General partner units - 1.1 million units issued and outstanding

2.5


—

Total partners' capital

482.2


—

Parent net investment

—


504.6

Noncontrolling interest

45.4


47.7

Total net equity

527.6


552.3

Total liabilities and equity

$
579.9


$
725.4



 


 

See notes accompanying the consolidated financial statements.


81


QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Year Ended
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
Period From August 14, 2013, through December 31, 2013

Period From January 1, 2013, through August 13, 2013

Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
Successor

Predecessor

Predecessor
 
Predecessor
 
 
(in millions)
OPERATING ACTIVITIES
 

 

 

 
 
Net income
 
$
20.6

 
$
41.4

 
$
71.0

 
$
63.5

Adjustments to reconcile net income to net cash provided by operating activities:
 

 

 

 

Depreciation and amortization
 
11.7

 
25.0

 
39.8

 
38.3

Equity-based compensation expense

0.4


—


—

 
—

Income from unconsolidated affiliates
 
(1.2
)
 
(3.8
)
 
(7.2
)
 
(4.4
)
Distributions from unconsolidated affiliates
 
1.3

 
4.9

 
7.8

 
7.7

Amortization of debt issuance costs
 
0.2

 
—

 
—

 
—

Net loss from asset sales
 
—

 
0.5

 
—

 
—

Changes in operating assets and liabilities:
 

 

 

 

Accounts receivable
 
(8.3
)
 
17.8

 
(2.4
)
 
(8.4
)
Accounts payable and accrued expenses
 
0.3

 
8.9

 
(1.6
)
 
0.9

Other
 
6.6

 
(3.8
)
 
(0.4
)
 
(0.1
)
Net cash provided by operating activities
 
31.6

 
90.9

 
107.0

 
97.5

INVESTING ACTIVITIES
 
 
 
 
 
 
 

Property, plant and equipment
 
(14.2
)
 
(9.1
)
 
(43.7
)
 
(28.6
)
Proceeds from sale of assets
 
0.5

 
0.6

 
0.3

 
0.1

Net cash used in investing activities
 
(13.7
)
 
(8.5
)
 
(43.4
)
 
(28.5
)
FINANCING ACTIVITIES
 

 

 

 

Repayments of long-term debt (to related party)
 
(95.5
)
 
(66.4
)
 
(43.6
)
 
(63.6
)
Long-term debt issuance costs
 
(3.3
)
 
—

 
—

 
—

Net proceeds from initial public offering
 
449.6

 
—

 
—

 
—

Proceeds from initial public offering distributed to parent
 
(351.1
)
 
—

 
—

 
—

Contributions from (distributions to) parent, net
 
9.6

 
(12.2
)
 
(14.5
)
 
1.0

Distribution to unitholders

(7.1
)

—


—


—

Distribution to noncontrolling interest
 
(2.2
)
 
(4.1
)
 
(6.6
)
 
(5.4
)
Net cash provided by (used in) financing activities
 
—

 
(82.7
)
 
(64.7
)
 
(68.0
)
Change in cash and cash equivalents
 
17.9

 
(0.3
)
 
(1.1
)

1.0

Beginning cash and cash equivalents
 
1.1

 
1.4

 
2.5

 
1.5

Ending cash and cash equivalents
 
$
19.0

 
$
1.1

 
$
1.4


$
2.5

 
 
 
 
 
 
 
 
 
Non-cash investing activities
 
 
 
 
 
 
 
 
Change in capital expenditure accrual balance
 
$
4.3

 
$
(1.6
)
 
$
(1.3
)
 
$
(1.5
)
 
 
 

 
 

 
 

 
 
See notes accompanying the consolidated financial statements.


82


QEP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY

 
 
Successor
 
 
Limited Partners
 
 
 
 
 
 
 
 
 
 
Common Units
 
Subordinated Units
 
General Partner Units
 
Noncontrolling
Interest
 
Total Net Equity
 
 
Units
 
Amount
 
Units

Amount
 
Units
 
Amount
 
 
 
 
 
 
(in millions)
Balance at April 19, 2013 (inception - prior to initial public offering)
 
—

 
$
—

 
—

 
$
—

 
—

 
$
—

 
$
—

 
$
—

Contribution of net assets on August 14, 2013
 
3.7

 
72.2

 
26.7

 
287.3

 
1.1

 
2.2

 
46.1

 
407.8

Net proceeds from initial public offering
 
23.0

 
449.6

 
—

 
—

 
—

 
—

 
—

 
449.6

Proceeds from initial public offering distributed to parent
 
—

 
(117.5
)
 
—

 
(233.6
)
 
—

 
—

 
—

 
(351.1
)
Contributions from parent
 
—

 
1.1

 
—

 
8.5

 
—

 
—

 
—

 
9.6

Distributions to noncontrolling interest
 
—

 
—

 
—

 
—

 
—

 
—

 
(2.2
)
 
(2.2
)
Distributions to unitholders
 
—

 
(3.5
)
 
—

 
(3.5
)
 
—

 
(0.1
)
 
—

 
(7.1
)
Equity-based compensation
 
—

 
0.4

 
—

 
—

 
—

 
—

 
—

 
0.4

Other
 
—

 
0.1

 
—

 
—

 
—

 
(0.1
)
 
—

 
—

Net income for the period from August 14, 2013, through December 31, 2013
 
—

 
9.3

 
—

 
9.3

 
—

 
0.5

 
1.5

 
20.6

Balance at December 31, 2013
 
26.7

 
$
411.7

 
26.7

 
$
68.0

 
1.1

 
$
2.5

 
$
45.4

 
$
527.6


See notes accompanying the consolidated financial statements.


83


QEP MIDSTREAM PARTNERS, LP PREDECESSOR
CONSOLIDATED STATEMENTS OF EQUITY
 
 
Predecessor
 
 
Parent Net
Investment
 
Noncontrolling
Interest
 
Total Net Equity
Balance at December 31, 2010
 
$
390.5

 
$
52.8

 
$
443.3

Net income for the year ended December 31, 2011
 
60.3

 
3.2

 
63.5

Contributions from parent, net
 
1.0

 
—

 
1.0

Distribution of noncontrolling interest
 
—

 
(5.4
)
 
(5.4
)
Balance at December 31, 2011
 
451.8

 
50.6

 
502.4

Net income for the year ended December 31, 2012
 
67.3

 
3.7

 
71.0

Distributions to parent, net
 
(14.5
)
 
—

 
(14.5
)
Distribution of noncontrolling interest
 
—

 
(6.6
)
 
(6.6
)
Balance at December 31, 2012
 
504.6

 
47.7

 
552.3

Net income for the period from January 1, 2013, through August 13, 2013
 
38.9

 
2.5

 
41.4

Distributions to parent, net
 
(12.2
)
 
—

 
(12.2
)
Distribution of noncontrolling interest
 
—

 
(4.1
)
 
(4.1
)
Balance at August 13, 2013
 
$
531.3

 
$
46.1

 
$
577.4


See notes accompanying the consolidated financial statements.


84


QEP MIDSTREAM PARTNERS, LP
NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Description of Business and Basis of Presentation

Description of Business

QEP Midstream Partners, LP (the Partnership) was formed in Delaware on April 19, 2013, to own, operate, acquire and develop midstream energy assets. The Partnership's assets consist of ownership interests in four gathering systems and two FERC regulated pipelines through which we provide natural gas and crude oil gathering and transportation services in Colorado, North Dakota, Utah and Wyoming.

On August 14, 2013, the Partnership completed its initial public offering (the IPO) of 20,000,000 common units representing limited partner interests in the Partnership. In addition, as of September 4, 2013, the underwriters had exercised their option to purchase an additional 3,000,000 common units (refer to Note 3 - Initial Public Offering). Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (periods prior to the IPO on August 14, 2013), refer to QEP Midstream Partners, LP Predecessor (the Predecessor). References in this report to "QEP Midstream," the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after August 14, 2013, in the present tense or prospectively, refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of these financial statements, "QEP" refers to QEP Resources, Inc. and its consolidated subsidiaries, including the Partnership.

As part of the IPO, QEP Midstream Partners GP, LLC (the General Partner) and QEP Field Services Company (QEP Field Services), both QEP affiliates, collectively contributed to the Partnership (i) a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the Operating Company), QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C. (Rendezvous Pipeline), (ii) a 78% interest in Rendezvous Gas Services, L.L.C. (Rendezvous Gas Services), and (iii) a 50% equity interest in Three Rivers Gathering, L.L.C. (Three Rivers Gathering). The General Partner serves as general partner of the Partnership and together with QEP provides services to the Partnership pursuant to an Omnibus Agreement between the parties.

The Predecessor consists of all of the Partnership's gathering assets as well as a 38% equity interest in Uintah Basin Field Services, L.L.C. (Uintah Basin Field Services) and a 100% interest in all other gathering assets owned by QEP Field Services in the Uinta Basin (collectively referred to as the Uinta Basin Gathering System). The Uinta Basin Gathering System was retained by QEP Field Services and was not part of the assets conveyed to the Partnership.

Basis of Presentation

The consolidated financial statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The consolidated financial statements and accompanying notes prior to the IPO (August 14, 2013) relate to the Predecessor and have been prepared in accordance with GAAP on the basis of QEP's historical ownership of the Predecessor assets. The Predecessor's consolidated financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net investment, in lieu of owner's equity, in the audited consolidated financial statements. Further, management does not believe that these financial statements are necessarily comparable to the financial statements reported by the Partnership for periods subsequent to the IPO nor reflective of other transactions that resulted in the capitalization and start-up of the Partnership. Refer to Item 7 of Part II of this Annual Report on Form 10-K for a description of the significant factors affecting the comparability of the Predecessor's historical results of operations and those of the Partnership subsequent to the IPO.


85


Note 2 - Summary of Significant Accounting Policies

Revenue Recognition

QEP Midstream provides natural gas gathering and transportation services, primarily under fee-based contracts. Under these arrangements, we receive a fee or fees for one or more of the following services: firm and interruptible gathering or transmission of natural gas, crude oil, condensate, and water. The revenue we earn from these arrangements is generally directly related to the volume of natural gas, crude oil, or water that flows through the our systems and is not directly dependent on commodity prices. Revenue for these agreements is recognized at the time the service is performed. In certain of these contracts, the agreement provides for minimum annual payments or fixed demand charges which are recognized as revenue pursuant to the contract terms. In addition, under certain of these gathering agreements, we retain and sell condensate, which falls out of the natural gas stream during the gathering process. We recognize revenue from condensate sales upon transfer of title. The Partnership has deferred revenue of which a portion will be recognized as revenue pursuant to contractual terms with the remaining being recognized based on the outcome of certain litigation. Refer to Note 9 - Commitments and Contingencies.

Investment in Unconsolidated Affiliates

QEP Midstream uses the equity method to account for investment in unconsolidated affiliates. The investment in unconsolidated affiliates on the Unaudited Consolidated Balance Sheets equals our proportionate share of equity reported by the unconsolidated affiliates. The investment is assessed for possible impairment when events indicate that the fair value of the investment may be below the carrying value. When such a condition is deemed to be other than temporary, the carrying value of the investment is written down to its fair value, and the amount of the write-down is included in the determination of net income.

The unconsolidated affiliate of the Partnership and the ownership percentage as of December 31, 2013, was Three Rivers Gathering (50%). The unconsolidated affiliates of the Predecessor and the ownership percentages as of August 13, 2013, and December 31, 2012, were Uintah Basin Field Services (38%) and Three Rivers Gathering (50%), both of which are engaged in the gathering, transportation and compression of natural gas.

Noncontrolling Interests

QEP Midstream has a 78% interest in Rendezvous Gas Services, a joint venture with Western Gas, which owns a gas gathering system located in Wyoming. Rendezvous Gas Services is consolidated under the voting interest model and Western Gas' non-controlling interest is presented on the Consolidated Statements of Income and Consolidated Balance Sheets accordingly.

Use of Estimates

The preparation of the consolidated financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. Items subject to estimates and assumptions include the carrying amount of property, plant and equipment, valuation allowances for receivables, valuation of accrued liabilities and accrued revenue, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

Historically, the majority of the Predecessor’s operations were funded by QEP and managed under QEP’s centralized cash management program. Following the IPO, we maintain our own bank accounts and sources of liquidity and continue to utilize QEP's cash management expertise. Cash equivalents consist principally of repurchase agreements with maturities of three months or less. The repurchase agreements are highly liquid investments in overnight securities made through commercial-bank accounts that result in available funds the next business day.

Accounts Receivable Trade

QEP Midstream’s receivables consist of third party and QEP invoices. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. The Partnership had no allowance for bad-debt expense at December 31, 2013. As of December 31, 2013, the Partnership had $8.5 million in accounts receivable related to outstanding litigation. Refer to Note 9 - Commitments and Contingencies for additional information. The Predecessor’s allowance for bad-debt expense was $0.4 million and $0.3 million at December 31, 2012 and 2011, respectively.


86


Property, Plant and Equipment

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

Impairment of Long-Lived Assets

QEP Midstream evaluates whether long-lived assets have been impaired and determines if the carrying amount of its assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If impairment is indicated, fair value is calculated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset or a change in management’s intent to utilize the asset. There were no long-lived asset impairments recognized during 2013, 2012 or 2011.

Asset Retirement Obligations

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

Natural Gas Imbalances

Natural gas imbalance receivables or payables result from differences in gas volumes received and gas volumes delivered to customers. Natural gas volumes owed to or by QEP Midstream 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 QEP Midstream are valued at our weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.

Litigation and Other Contingencies

In accordance with Accounting Standards Codification (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 reviews contingencies to determine the adequacy of our accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Refer to Note 9 - Commitments and Contingencies.

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.

Credit Risk

Exposure to credit risk may be affected by the concentration of customers due to changes in economic or other conditions. Customers may 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.


87


The customers accounting for 10% or more of QEP Midstream's revenues for the period subsequent to the IPO on August 14, 2013 include:

 
Period From August 14, 2013, through December 31, 2013
QEP (revenue from affiliate)
$
32.8

Questar Gas Company
7.5


Fair Value Measurements

QEP Midstream did not have any assets accounted for at fair value as of December 31, 2013. The Predecessor did not have any assets accounted for at fair value as of December 31, 2012 or 2011. We believe the carrying values of our current assets and liabilities approximate fair value. The carrying amount of our affiliated long-term debt approximates fair value.

The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs are used in the calculation of asset retirement obligations include retirement costs and asset lives. Refer to Note 6 for a reconciliation of the Partnership’s asset retirement obligations.

Post-Retirement Employee Benefit Plans

QEP has various employee benefit plans, which include 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 financial statements, QEP Midstream is considered to be participating in the employee benefit plans of QEP; however, employees who support QEP Midstream remain employees of QEP. As a participant in the benefit plans, QEP Midstream recognizes as expense the allocation from QEP, if any, which is included in the general and administrative fee for the Post-IPO Period or general and administrative fee allocation from QEP prior to the IPO. However, QEP Midstream does not recognize any employee benefit plan liabilities.

Equity-Based Compensation

The Predecessor’s financial statements reflect various share-based compensation awards by QEP. These awards include stock options, restricted shares and performance share units. For purposes of these combined financial statements, the Predecessor recognized as expense in each period the required allocation from QEP, with the offset included in net parent equity.

In connection with the IPO, the Board adopted the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan (the LTIP) for officers, directors and employees of the General Partner and its affiliates, and any consultants, affiliates of the General Partner or other individuals who perform services for the Partnership. The LTIP provides for the grant, at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other equity-based awards. Refer to Note 8 for additional information on the Partnerships LTIP.

Income Taxes

QEP Midstream's financial statements do not include income tax allocation as the Partnership is treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the taxable income. The allocation of taxable income to our individual partners may vary substantially from net income reported in our consolidated statements of income.

Recent Accounting Developments

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

88



Note 3 - Initial Public Offering

On August 14, 2013, the Partnership completed its IPO selling 20,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $21.00 per common unit. The Partnership 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 $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 the Partnership.

The Partnership used the net proceeds to repay its outstanding debt balance with QEP, which was assumed with the assets contributed to the Partnership, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to the Partnership.

The following is a reconciliation of proceeds from the IPO (in millions):
Total proceeds from the IPO
 
$
483.0

Offering costs
 
(33.4
)
Net proceeds from the IPO
 
449.6

Revolving credit facility origination fees
 
(3.0
)
Repayment of outstanding debt with QEP
 
(95.5
)
Net proceeds distributed to QEP from the IPO
 
$
351.1


As of December 31, 2013, the Partnership's ownership consisted of the following:
 
 
Units
 
% Ownership
Limited partner common units - QEP
 
3,701,750

 
6.8
%
Limited partner common units - public
 
23,008,998

 
42.2
%
Limited partner subordinated units - QEP
 
26,705,000

 
49.0
%
General partner units
 
1,090,117

 
2.0
%
Total QEP Midstream units
 
54,505,865

 
 

Contribution, Conveyance and Assumption Agreement and Concurrent Transactions

On August 14, 2013, in connection with the closing of the IPO, the Partnership entered into a Contribution, Conveyance and Assumption Agreement (the Contribution Agreement) with QEP Field Services, the General Partner and the Operating Company. Immediately prior to the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

•
QEP Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2% of the equity value of the Partnership at the closing of the IPO;
•
the General Partner contributed to the Partnership, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2% general partner interest in the Partnership and (b) all the incentive distribution rights of the Partnership;
•
QEP Field Services contributed to the Partnership, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in the Partnership, (b) 26,705,000 subordinated units representing a 49% limited partner interest in the Partnership and (c) the right to receive a distribution from the Partnership; and
•
the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to the Partnership in exchange for the issuance of 20,000,000 common units.

Subsequent to the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units in the Partnership, which reduced QEP Field Services' common unit interest in the Partnership from 12.3% to 6.8%.


89


The contribution of QEP Field Services' and the General Partner's limited liability company interest in the Operating Company to the Partnership was valued using the carryover book value of the Operating Company, as the transaction is a transfer of assets between entities under common control, as follows (in millions):
Cash and cash equivalents
 
$
1.1

Accounts receivable, net
 
26.4

Property, plant and equipment, net
 
485.6

Investment in unconsolidated affiliate
 
27.9

Account payable and accrued expenses
 
(21.1
)
Long-term debt to related party
 
(95.5
)
Asset Retirement Obligation
 
(11.8
)
Other liabilities
 
(4.8
)
Net assets
 
$
407.8


First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP

On August 14, 2013, in connection with the closing of the IPO, the Agreement of Limited Partnership was amended and restated by the First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (as amended and restated, the Partnership Agreement).

Note 4 - Related Party Transactions

The Partnership

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of December 31, 2013, QEP Field Services owns 3,701,750 common units and 26,705,000 subordinated units representing a 55.8% limited partner interest in us. In addition, our General Partner owns 1,090,117 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEP Field Services and QEP are considered to be related party transactions because our General Partner and its affiliates own more than 5% of our equity interests. Following the IPO, in addition to the agreements discussed in Note 3 - Initial Public Offering, the Partnership entered into the following agreements with QEP.

Omnibus Agreement

On August 14, 2013, in connection with the closing of the IPO, the Partnership entered into an Omnibus Agreement (the Omnibus Agreement) with QEP Field Services, the General Partner, the Operating Company and QEP, which addresses the following matters:

•
the Partnership's payment of an annual amount to QEP, initially in the amount of $13.8 million, for the provision of certain general and administrative services by QEP to the Partnership, including a fixed annual fee of approximately $1.4 million for executive management services provided by certain officers of the General Partner, who are also executives of QEP. The remaining portion of this annual amount reflects an estimate of the costs QEP will incur in providing the services;
•
the Partnership's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and its affiliates that are reimbursed under the Partnership's Partnership Agreement), as well as any other out-of-pocket expenses incurred by QEP on the Partnership's behalf; and
•
an indemnity by QEP for certain environmental and other liabilities, and the Partnership's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of the Partnership's assets that occur after the closing of the IPO.

As long as QEP controls the General Partner, the Omnibus Agreement will remain in full force and effect. If QEP 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.

For the period from August 14, 2013, through December 31, 2013, the Partnership was charged $4.6 million under the Omnibus Agreement by QEP.

90



Service Agreements

At the closing of the IPO, the Partnership entered into various midstream agreements with QEP including, but not limited to, natural gas, crude oil, water and condensate gathering and transportation agreements, a fixed price condensate purchase agreement, operating agreements and other service agreements. The Partnership believes 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. For the period from August 14, 2013, through December 31, 2013, the Partnership generated approximately $32.8 million of its total revenues under agreements with QEP.

The Predecessor

Prior to the IPO, the Predecessor had the following agreements in place with QEP resulting in affiliate transactions.

Centralized Cash Management

QEP operated a cash management system whereby excess cash from its various subsidiaries, held in separate bank accounts, was consolidated into a centralized account. Sales and purchases related to third-party transactions were settled in cash but were received or paid by QEP within the centralized cash management system.

Affiliated Debt

The Predecessor's long-term debt consisted of an allocation from QEP Field Services of its total long-term debt related to QEP Field Services' debt agreements with QEP. During the first quarter of 2012, QEP Field Services had a $250.0 million revolving debt agreement (the 2011 Agreement) with QEP for its working capital requirements, in which QEP Field Services was charged a variable interest rate. Interest during the first quarter of 2012 was allocated to the Predecessor based on an interest rate equal to QEP's average borrowing rate, which was 5.2% in the first quarter of 2012 and historically was paid through non-cash intercompany settlements. In April 2012, QEP Field Services entered into new debt agreements with QEP replacing the 2011 Agreement with a $250.0 million promissory note, 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, with a maturity date of April 1, 2014. In addition, QEP Field Services entered into a $1.0 billion "revolving credit" type promissory note with QEP, which matures on April 1, 2017, to assist with funding of capital expenditures. Accordingly, all amounts have been classified as "Long-term debt to related party" in our Consolidated Balance Sheets. Both agreements require QEP Field Services to pay QEP interest during the last nine months of 2013 at a 6.0% fixed rate. Interest allocated to the Predecessor under these notes in the first quarter of 2013 was based on the fixed-rate due to QEP and $2.8 million was settled in cash. Further, $3.2 million was settled in cash related to intercompany interest expense in 2012. QEP Field Services was in compliance with its covenants under the agreements for all periods prior to the IPO, and there are no letters of credit outstanding. At December 31, 2012, allocated debt for the Predecessor was $131.1 million. In connection with the IPO, $95.5 million of affiliated debt was assumed by the Partnership and was repaid in full on August 14, 2013, with proceeds of the IPO extinguishing all affiliated debt of the Partnership.

Allocation of Costs

The employees supporting the Predecessor's operations were employees of QEP. General and administrative expenses allocated to the Predecessor were $13.6 million for the period from January 1, 2013, through August 13, 2013, and $17.0 million for the year ended December 31, 2012, respectively. The consolidated financial statements of the Predecessor include direct charges for operations of our assets and costs allocated by QEP. These costs were reimbursed and related 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) compensation, equity-based compensation, benefits and pension and post-retirement costs. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable.


91


The following table summarizes the related party income statement transactions of the Predecessor with QEP: 
 
 
Period From January 1, 2013, through August 13, 2013
 
Year Ended December 31, 2012
 
Year Ended December 31, 2011
 
 
(in millions)
Revenues from affiliate
 
$
55.0

 
$
79.7

 
69.5

Interest expense to affiliate
 
(2.6
)
 
(8.7
)
 
(12.8
)

Note 5 - Property, Plant and Equipment

A summary of the historical cost of QEP Midstream's property, plant and equipment is as follows: 
 
 
Estimated Useful
Lives
 
December 31, 2013
 
December 31, 2012
 
 
 
 
Successor
 
Predecessor
 
 
 
 
(in millions)
Gathering equipment
 
5 to 40 years
 
$
737.9

 
$
907.7

General support equipment
 
3 to 30 years
 
—

 
11.1

Total property, plant and equipment
 
 
 
737.9

 
918.8

Accumulated depreciation
 
 
 
(244.5
)
 
(284.7
)
Total net property, plant and equipment
 
 
 
$
493.4

 
$
634.1


Note 6 - Asset Retirement Obligations

The QEP Midstream records asset retirement obligations when there are legal obligations associated with the retirement of tangible long-lived assets. The fair values of such costs are estimated by our personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO liability may occur due, among other things, 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 our credit-adjusted, risk-free interest rate.

The following is a reconciliation of the changes in the ARO liability for the periods specified below (in millions):
 
2013
 
Asset Retirement
Obligations
 
Predecessor
ARO liability at January 1,
$
16.3

Accretion
0.7

ARO liability at August 13,(1)
$
17.0

 
 
 
Successor
ARO liability at August 14,
$
11.8

Accretion
0.3

Liabilities incurred
0.3

Revisions
1.0

Liabilities Settled
(0.1
)
ARO liability at December 31,
$
13.3

            
(1) 
The ending balance of the Predecessor includes the assets that were retained by QEP Field Services and not conveyed to the Partnership in connection with the IPO. See Note 1 - Description of Business and Basis of Presentation, for additional information on the Partnership's assets.

92



Note 7 - Debt

On August 14, 2013, in connection with the IPO, we entered into a $500.0 million senior secured revolving credit facility (the Credit Facility) with a group of financial institutions. The Credit Facility matures on August 14, 2018, and contains an accordion provision that would allow for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership'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.

Loans under the Credit Facility will bear interest at the Partnership's option at a variable rate per annum equal to either:
•
a base rate, which will be the highest of (i) the administrative agent's prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or
•
LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio.

As of December 31, 2013, there was no debt outstanding under the Credit Facility, and the Partnership was in compliance with the covenants under the credit agreement. For the period from August 14, 2013 to December 31, 2013 the Partnership incurred and paid $0.7 million of commitment fees.

All debt outstanding prior to and at the IPO relates to intercompany debt with QEP discussed in Note 4 - Related Party Transactions. The net proceeds from the IPO were used to pay off the $95.5 million of debt assumed by the Partnership in connection with the IPO.

Note 8 - Equity-Based Compensation

In connection with the IPO, the Board adopted the LTIP for officers, directors and employees of the General Partner and its affiliates, and any consultants, affiliates of the General Partner or other individuals who perform services for the Partnership. The Partnership reserved 5,341,000 common units for issuance pursuant to and in accordance with the LTIP.

The LTIP provides for the grant, at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other equity-based awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the LTIP to 5,341,000 common units. Common units cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a designated committee thereof.

Common Units

On August 14, 2013, the Board granted 3,250 common units to the independent director of the Board at $21.00 per unit, which vested immediately. On November 8, 2013, the Board granted a total of 5,748 common units to two additional independent directors of the Board at $22.62 per unit, which vested immediately. The fair value of common unit awards granted to non-employee directors is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized at the time of grant, since the common unit awards vest immediately and are non-forfeitable.

Phantom Units

On August 14, 2013, the Board granted 39,500 phantom units with dividend equivalent rights to employees of the General Partner, including executive officers, which vest in equal installments over a three-year period from the grant date. The fair value of phantom unit awards granted to employees is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized over the vesting period of three years. The phantom units granted in 2013 are payable in new common unit issuances.


93


The following is a summary of the Partnership's phantom unit award activity for the period ended December 31, 2013:
 
 
Phantom Units Outstanding
 
Weighted-Average Grant-Date Fair Value
Unvested balance at beginning of the period
 
—

 
$
—

Granted
 
39,500

 
22.03

Vested
 
—

 
—

Forfeited
 
(1,250
)
 
22.03

Unvested balance at December 31, 2013
 
38,250

 
$
22.03


Total compensation expense recognized for the common unit and phantom unit awards since the IPO was $0.4 million, and the total amount of unrecognized compensation cost related to the phantom unit award was $0.7 million as of December 31, 2013, which is expected to be recognized over the remaining vesting period of 2.6 years.

Note 9 - Commitments and Contingencies

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 consolidated 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. The Partnership's 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 the resolution of pending proceedings will not have a material effect on our financial position, results of operations or cash flows.

Litigation

At the closing of the IPO, the assets and agreement subject to the ongoing litigation between QGC and QEP Field Services, styled Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah, were assigned to the Partnership. QEP Field Services' former affiliate, 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, an accounting and declaratory judgment related to a 1993 gathering agreement and a 1998 amendment (the 1993 Agreement) executed when the parties were affiliates. Under the 1993 Agreement, certain of our systems provide gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the 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. QGC was netting the disputed amount from its monthly payment of the gathering fees to QEP Field Services and has continued to net such amount from its monthly payment to the Partnership. As of December 31, 2013, the Partnership has deferred revenue of $8.5 million related to the QGC disputed amount. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined above in "Note 4 - Related Party Transactions").

Note 10 - Net Income Per Limited Partner Unit

Net income per unit is applicable to the Partnership's limited partner common and subordinated units. Net income per unit is calculated following the two-class method as the Partnership has more than one class of participating securities including common units, subordinated units, general partner units, certain equity-based compensation awards and incentive distribution rights. Net income per unit is calculated by dividing the limited partners' interest in net income attributable to the Partnership, after deducting any General Partner's incentive distributions, by the weighted-average number of outstanding common and subordinated units outstanding.


94


Net income per unit is only calculated for the period subsequent to the IPO as no units were outstanding prior to August 14, 2013. As of December 31, 2013, the basic net income per unit and the diluted net income per unit were equal as there were no potentially dilutive units outstanding.

The following tables set forth distributions in excess of net income attributable to QEP Midstream and the calculation of net income per unit for the period from August 14, 2013, through December 31, 2013 (in millions, except per unit amounts).

Net income attributable to QEP Midstream
 
$
19.1

General partner's distribution declared(1)
 
(0.5
)
Limited partners' distribution declared on common units(1)
 
(10.4
)
Limited partners' distribution declared on subordinated units(1)
 
(10.4
)
Distribution in excess of net income attributable to QEP Midstream
 
$
(2.2
)
            
(1) 
On October 23, 2013, the Partnership declared its first quarterly cash distribution totaling $7.1 million, or $0.13 per unit for the third quarter of 2013. On January 23, 2014, the Partnership declared its quarterly cash distribution totaling $14.2 million, or $0.26 per unit, for the fourth quarter of 2013 (refer to Note 12 - Subsequent Events). During the period from August 14, 2013, through December 31, 2013, no distributions related to the General Partner's incentive distribution rights were declared.


 
 
General Partner
 
Limited Partners' Common Units
 
Limited Partners' Subordinated Units
 
Total
 
 
(in million, except per unit amounts)
Net income attributable to QEP Midstream:
 
 
 
 
 
 
 
 
Distribution declared
 
$
0.5

 
$
10.4

 
$
10.4

 
$
21.3

Distributions in excess of net income attributable to QEP Midstream
 
—

 
(1.1
)
 
(1.1
)
 
(2.2
)
Net income attributable to QEP Midstream
 
$
0.5

 
$
9.3

 
$
9.3

 
$
19.1

 
 
 
 
 
 
 
 
 
Weighted-average limited partner units outstanding:
Basic and Diluted
 
1.1

 
26.7

 
26.7

 
54.5

Net income per limited partner unit attributable to the QEP Midstream
Basic and Diluted
 
 
 
$
0.35

 
$
0.35

 
 


95


Note 11 - Quarterly Financial Information (unaudited)

The following table provides a summary of unaudited quarterly financial information.

 
First Quarter

Second Quarter
 
Period from July 1, 2013 to August 13, 2013
 
Period from August 14, 2013 to September 30, 2013
 
Fourth Quarter
 
Predecessor
 
Predecessor
 
Predecessor
 
Successor
 
Successor
2013
(in millions, except per unit amounts)
Revenues
$
40.1

 
$
40.1

 
$
20.1

 
$
16.4

 
$
31.7

Operating income
15.8

 
16.6

 
7.8

 
7.4

 
12.9
Net income
16.0

 
17.7

 
7.7

 
7.1

 
13.5
Net income attributable to QEP Midstream or Predecessor
15.4

 
16.4

 
7.1

 
6.5

 
12.6
Net income attributable to QEP Midstream Partners, LP subsequent to initial public offering per limited partner unit:

 

 

 

 

    Common
—

 
—

 
—

 
$
0.12

 
$
0.23

    Subordinated
—

 
—

 
—

 
0.12

 
0.23

Distributions declared per limited partner common unit
—

 
—

 
—

 
0.13

 
0.26

 
First Quarter
 
Second Quarter
 
Third Quarter
 
Fourth Quarter
2012 - Predecessor
(in millions)
Revenues
$
41.9

 
$
39.7

 
$
40.8

 
$
39.8

Operating income
20.5

 
18.2

 
17.3

 
16.4

Net income
20.6

 
17.3

 
18.2

 
14.9

Net income attributable to Predecessor
19.8

 
16.4

 
17.2

 
13.9



Note 12 - Subsequent Events

On January 23, 2014, the Partnership declared its quarterly cash distribution totaling $14.2 million, or $0.26 per unit, for the fourth quarter of 2013.This distribution was paid on February 14, 2014, to unitholders of record on the close of business on February 4, 2014. No distributions related to the General Partner's incentive distribution rights were declared.





96


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures
 
The management of our General Partner, with the participation of the chief executive officer and chief financial officer of our General Partner, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of December 31, 2013. Based on such evaluation, management has concluded that, as of December 31, 2013, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
 
Changes in Internal Controls

There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2013, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
 
Internal Control Over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on such company's internal control over financial reporting in its annual report. In addition, our independent registered public accounting firm must attest to our internal control over financial reporting. This Annual Report on Form 10-K does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. Management will be required to provide an assessment of effectiveness of our internal control over financial reporting in our Annual Report on Form 10-K for the year ending December 31, 2014. We are not required to comply with the auditor attestation requirement of Section 404 of the Sarbanes-Oxley Act while we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012 (JOBS Act).

ITEM 9B. OTHER INFORMATION
 
None.



97


PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of QEP Midstream Partners, LP

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

Our General Partner has seven directors. The Board has determined that three of its directors - Susan O. Rheney, Don A. Turkleson, and Gregory C. King - are independent under the independence standards of the NYSE.

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

Director Independence

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

Committees of the Board of Directors

The Board has an audit committee and a conflicts committee and may have such other committees as the Board shall determine from time to time. As permitted by NYSE rules, the Board does not currently have a compensation committee, but rather the Board approves equity based compensation to directors and officers.

Audit Committee

Susan O. Rheney serves as the chairperson, and Don A. Turkleson and Gregory C. King are members, of our Audit Committee. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee.

The Audit Committee has a written charter adopted by the Board of Directors of our General Partner, which is available on our website at http://qepm.investorroom.com/committee-charters. The audit committee charter requires the Audit Committee to assess and report to the Board on the adequacy of the charter on an annual basis.

Audit Committee Financial Expert. Based on the attributes, education, and experience requirements set forth in the rules of the SEC, the Board has determined that each of Susan O. Rheney, Don A. Turkleson, and Gregory C. King qualifies as an "Audit Committee Financial Expert" as more fully detailed in the biographies set forth below.


98


Conflicts Committee

Gregory C. King serves as the chairman, and Susan O. Rheney and Don A. Turkleson are members, of the Conflicts Committee of the Board. The Conflicts Committee reviews specific matters that may involve conflicts of interest in accordance with the terms of our Partnership Agreement. Any matters approved by the Conflicts Committee in good faith will be deemed to be approved by all of our partners and to not be a breach by our General Partner of any duties it may owe us or our unitholders. The members of the Conflicts Committee may not be officers or employees of our General Partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of the Conflicts Committee may not own any interest in our General Partner or any interest in us or our subsidiaries other than common units or awards under our incentive compensation plan.

The Conflicts Committee has a written charter adopted by the Board, which is available on our website at http://qepm.investorroom.com/committee-charters.

Directors and Executive Officers of QEP Midstream Partners GP, LLC

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

Name
 
Age
 
Position with QEP Midstream Partners GP, LLC
Charles B. Stanley
 
55

 
Chairman of the Board of Directors, President and Chief Executive Officer
Richard J. Doleshek
 
55

 
Director, Executive Vice President, Chief Financial Officer and Treasurer
Perry H. Richards
 
53

 
Director, Senior Vice President and General Manager
Abigail L. Jones
 
53

 
Vice President, Compliance and Corporate Secretary
Alice B. Ley
 
40

 
Vice President, Controller and Chief Accounting Officer
Christopher K. Woosley
 
44

 
Vice President and General Counsel
Margo Fiala
 
50

 
Vice President - Human Resources
S. Scott Gutberlet
 
49

 
Director
Susan O. Rheney
 
53

 
Director
Don A. Turkleson
 
59

 
Director
Gregory C. King
 
53

 
Director

Charles B. Stanley.    Charles B. Stanley was appointed President, Chief Executive Officer and chairman of the Board in April 2013. Mr. Stanley has served as President, Chief Executive Officer and a director of QEP since June 2010. He served as Executive Vice President and Chief Operating Officer of Questar Corporation from 2002 until QEP’s spin-off in June 2010. Mr. Stanley devotes the majority of his time to his roles at QEP and also spends time, as needed, directly managing our business and affairs. Currently, 10% of his total business time is devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops or QEP sells or spins off its midstream business. Mr. Stanley also served as a director of Questar Corporation from 2002 until QEP’s spin-off in June 2010. Prior to joining Questar Corporation, he served as President, Chief Executive Officer and a director of El Paso Oil and Gas Canada, an upstream oil and gas company from 2000 to 2002, and as President and Chief Executive Officer of Coastal Gas International Company, a midstream infrastructure development company, from 1995 to 2000. He is a director of Hecla Mining Company and serves on the boards of various natural gas industry trade organizations, including America’s Natural Gas Alliance and the American Exploration and Production Council. In concluding that Mr. Stanley is qualified to serve as a director, the Board considered, among other things, his more than 28 years of experience in the international and domestic upstream and midstream oil and gas industry.

Richard J. Doleshek.    Richard J. Doleshek was appointed as a Director and Executive Vice President and Chief Financial Officer of our General Partner in April 2013. Mr. Doleshek was appointed Chief Accounting Officer of our General Partner in December 2013. Mr. Doleshek has served as Executive Vice President, Chief Financial Officer and Treasurer of QEP since June 2010. He served as Executive Vice President, Chief Financial Officer of Questar Corporation from 2009 until QEP’s spin-off in June 2010. Mr. Doleshek devotes the majority of his time to his roles at QEP and also spends time, as needed, directly

99


managing our business and affairs. Currently, 10% of his total business time is devoted to our business and affairs, although this amount may increase or decrease in future periods as our business develops or QEP sells or spins off its midstream business. Prior to joining Questar Corporation, Mr. Doleshek was Executive Vice President and Chief Financial Officer of Hilcorp Energy Company from 2001 to 2009. In concluding that Mr. Doleshek is qualified to serve as a director, the Board considered, among other things, his more than 30 years of experience in the upstream and midstream oil and gas industry.

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

Abigail L. Jones.    Abigail L. Jones was appointed Secretary and Vice President of Compliance of our General Partner in April 2013. Ms. Jones has served as Corporate Secretary and Vice President of Compliance of QEP since June 2010. Ms. Jones devotes the majority of her time to her roles at QEP and also spends time, as needed, directly managing our business and affairs. Ms. Jones served as Corporate Secretary and Vice President of Compliance of Questar Corporation from 2007 until QEP’s spin-off in June 2010. Ms. Jones joined the Legal Department of Questar Corporation in 2002. In 2004, she became Assistant Corporate Secretary, and in 2005, she became Corporate Secretary of Questar Corporation. In 2007, she assumed the role of Vice President, Compliance for Questar Corporation.

Alice B. Ley. Alice B. Ley was appointed Vice President, Controller and Chief Accounting Officer of our General Partner in March 2014. Ms. Ley was also appointed Vice President, Controller and Chief Accounting Officer of QEP in March 2014. Ms. Ley devotes the majority of her time to her roles at QEP and also spends time, as needed, directly managing our business and affairs. Ms. Ley served as Director of Financial Reporting at QEP from September 2012 until November 2013, and served as Interim Controller from November 2013 until March 2014. Prior to joining QEP, Ms. Ley was employed by Frontier Oil Corporation as an Accounting/ Financial Analyst Manager from 2001 until 2011 and at Arthur Andersen, LLP as an Audit Manager in the Energy Division from 1996 until 2001. She is a Certified Public Accountant.

Christopher K. Woosley. Christopher K. Woosley was appointed Vice President and General Counsel of our General Partner in March 2014. Mr. Woosley has served as Vice President and General Counsel of QEP since 2012 and served as a Senior Attorney from 2010 until 2012. Mr. Woosley devotes the majority of his time to his roles at QEP and also spends time, as needed, directly managing our business and affairs. Prior to joining QEP, Mr. Woosley served as outside counsel to Questar as a partner in the law firm Cooper Newsome & Woosley PLLP from 2003 until 2010.

Margo Fiala. Margo Fiala was appointed Vice President - Human Resources of our General Partner in March 2014. Ms. Fiala has served as Vice President - Human Resources of QEP since 2010. Ms. Fiala devotes the majority of her time to her roles at QEP and also spends time, as needed, directly managing our business and affairs. Prior to joining QEP, Ms. Fiala held a variety of roles at Suncor Energy, including Director of Human Resources, from 1995-2010.

S. Scott Gutberlet.    S. Scott Gutberlet was appointed as a Director of the Board in April 2013. Mr. Gutberlet has served as Vice President of Commercial and Technical Services of QEP Energy Company, a subsidiary of QEP, since April 2012. Mr. Gutberlet joined the reservoir engineering department of Questar Corporation in 2006. In 2007, he became the Director of Midstream Commercial and Technical Operations and, in 2008, he became the General Manager of the Uinta Basin Division for Questar Exploration & Production Company. He then served as Director of Investor Relations for QEP until assuming his current position. In concluding that Mr. Gutberlet is qualified to serve as a director, the Board considered, among other things, his more than 26 years of experience in the upstream and midstream oil and gas industry.

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

100


considered, among other things, her extensive financial knowledge and her experience as a director for companies in the energy industry, including her experience as a director of a midstream master limited partnership.

Don A. Turkleson. Don A Turkleson was appointed as an independent Director of the Board in November 2013. Mr. Turkleson is currently Vice President and Chief Financial Officer of Gulf Coast Energy Resources, LLC, a privately held exploration and production company focusing on Texas and Louisiana conventional oil and gas plays onshore and offshore. He has served in that role since 2012. From 2010 to 2012, he served as Chief Financial Officer of Laurus Energy, Inc., a privately held company developing underground coal gasification projects. From 1997 to 2009, he was the Senior Vice President and Chief Financial Officer of Cheniere Energy, Inc., a publicly traded company involved in the development, construction and operation of LNG receiving terminals, and served on the board of directors of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P. from 2007 to 2012. Mr. Turkleson currently serves on the Board of Directors of Miller Energy Resources, Inc., an oil and natural gas exploration, production and drilling company operating multiple projects in North America, where he has served as a director since 2011. He also serves on the board of directors of Cheniere Energy Partners LP Holdings, LLC, a publicly traded company where he has served as director since 2013. In concluding that Mr. Turkleson is qualified to serve as a director, the Board considered, among other things, his extensive financial knowledge and his experience as a director for companies in the energy industry.

Gregory C. King. Gregory C. King was appointed as an independent Director of the Board in November 2013. Mr. King is currently a Principal of GCK Ventures, LLC. He served as President of Valero Energy Corporation until December 31, 2007. He joined Valero in July 1993. Throughout his nearly 15 years at Valero, Mr. King served in several key positions, including Executive Vice President and Chief Operating Officer, Executive Vice President and General Counsel and Associate General Counsel. He also served on the Board of Directors of Valero, L.P., which is now NuStar Energy, L.P. Prior to joining Valero he was a partner in the Houston law firm of Bracewell & Giuliani. Since 2011, Mr. King has served on the Board of Directors of OTLP GP, LLC, the general partner of Oiltanking Partners, L.P., a publicly traded master limited partnership engaged in the independent storage and transportation of crude oil, refined petroleum products and liquefied petroleum gas. In concluding that Mr. King is qualified to serve as a director, the Board considered, among other things, his extensive financial knowledge and his experience as a director for companies in the energy industry.

Corporate Governance

Our corporate governance guidelines are available on our website at http://qepm.investorroom.com/corporate-governance by selecting "Corporate Governance Guidelines." In summary, our Corporate Governance Guidelines provide the functional framework of the Board of Directors of our General Partner, including its roles and responsibilities. These guidelines also address board independence, committee composition, the process for director selection and director qualifications.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires the directors and executive officers of our General Partner and persons who own more than 10% of a registered class of our equity securities, to file reports of beneficial ownership on Form 3 and changes in beneficial ownership on Forms 4 or 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the person required to file reports, we believe that each of the directors and executive officers of our General Partner and persons who own more than 10% of a registered class of our equity securities has complied with the applicable reporting requirements for transactions in our equity securities during the fiscal year ended December 31, 2013.

Code of Business Conduct and Ethics

Our Code of Business Conduct and Ethics is available on our website at http://qepm.investorroom.com/corporate-governance
by clicking on “Code of Business Conduct and Ethics.” This code of ethics applies to officers and directors of the Partnership, including its principal executive officer, principal accounting officer or controller, or person performing similar functions.

Under this code of ethics, these senior financial officers must, among other things:
•
act with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
•
provide full, fair, accurate, timely and understandable disclosure in reports and documents filed with, or submitted to, the SEC, and in other public communications;
•
comply with applicable laws, governmental rules and regulations, including insider trading laws; and
•
promote the prompt internal reporting of potential violations or other concerns related to this code of ethics to the chair of the Audit Committee and to the appropriate person or persons identified in the code of business conduct.

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We make available free of charge, within the "Corporate Governance" subsection of the "Investors" section of our website at http://www.qepm.com and in print to any interested party who so requests, the Code of Business Conduct and Ethics and our Corporate Governance Guidelines, audit committee charter, and conflicts committee charter. Requests for print copies may be directed to Investor Relations, QEP Midstream Partners, L.P., 1050 17th Street, Suite 500, Denver, Colorado 80265, or by telephone at 1-303-672-6900. We will post on our website all waivers to or amendments of the Code of Business Conduct and Ethics, which are required to be disclosed by applicable law and the NYSE's Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report we file with or furnish to the SEC.


ITEM 11. EXECUTIVE COMPENSATION

We are providing compensation disclosure that satisfies the requirements applicable to emerging growth companies, as defined in the JOBS Act. We completed the IPO on August 14, 2013. Neither we nor our General Partner had accrued any financial obligations related to the compensation for our executive officers, or other personnel, for any periods prior to the IPO. Therefore, the amounts shown in the Summary Compensation Table below reflect only compensation amounts allocated to us with respect to services provided from and after the date of our initial public offering.

Neither we, our General Partner, nor any of our subsidiaries have employees. QEP is contractually obligated to provide its and its subsidiaries' employees and other personnel necessary to conduct our operations. This includes all of our executive officers. For our executive officers who are also providing services to QEP and its affiliates other than us and our General Partner, compensation is paid by QEP or its applicable affiliate. We pay QEP a fixed amount each month for the services of our executive officers. The amount we pay to QEP for services provided to us by our executive officers is outlined in the Omnibus Agreement and serves as the amount we report as "Salary" in our Summary Compensation Table.

The Board has adopted the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan on our behalf. Certain eligible officers and non-management directors of our General Partner and its affiliates who make significant contributions to our business are eligible to receive awards under the LTIP. In addition, certain eligible employees of our General Partner's affiliates and other individuals who indirectly support our business may also be granted awards under the LTIP. Awards under the LTIP will be approved by the Board.

Named Executive Officer Compensation

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 executive compensation paid to our named executive officers of our General Partner (NEOs) identified below for their services in 2013. For 2013, the NEOs were:
•
Charles B. Stanley, President and Chief Executive Officer
•
Richard J. Doleshek, Executive Vice President, Chief Financial Officer, and Chief Accounting Officer
•
Perry H. Richards, Senior Vice President

All of the NEOs are employed by QEP and devoted less than a majority of their time to the management of our business in 2013. Except with respect to awards that may be granted under our LTIP, all responsibility and authority for compensation-related decisions for the NEOs remain with the compensation committee of the board of directors of QEP (the QEP Compensation Committee), currently composed of five independent directors, and are not subject to any approval by us, the Board or any committees thereof. Other than awards granted under the LTIP, QEP has the ultimate decision-making authority with respect to the total compensation of its and its subsidiaries' executive officers and its employees. The fixed amount charged to us for services of the NEOs listed above is agreed upon and set by the Omnibus Agreement.

All determinations with respect to awards to be made under the LTIP to executive officers of QEP are made by the Board.

Summary Compensation Table

The following table summarizes total compensation for services rendered by the NEO's during the Post-IPO Period.  Amounts shown in the Salary column reflect the fixed fees that we pay to QEP for the services of each of the NEOs under the terms of the Omnibus Agreement and do not reflect amounts actually paid to the NEOs by QEP.  Amounts shown in the Unit Awards column reflect awards by QEP Midstream made under the LTIP directly to the NEOs. 


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Summary Compensation Table
Name and Principal Position
 
Year
 
Salary
 
Unit Awards (4)
 
Total
Charles B. Stanley
 
2013
 
$
249,340

(1 
) 
$
220,300

 
$
469,639

Chairman, President, and Chief Executive Officer
Richard J. Doleshek
 
2013
 
134,260

(2 
) 
165,225

 
299,483

Executive Vice President, Chief Financial Officer, and Chief Accounting Officer
Perry H. Richards
 
2013
 
153,440

(3 
) 
55,075

 
208,512

Senior Vice President
            
(1) 
The amount shown reflects a pro-rated amount of the annualized fixed fee for Mr. Stanley's services of $650,000.
(2)  
The amount shown reflects a pro-rated amount of the annualized fixed fee for Mr. Doleshek's services of $350,000.
(3) 
The amount shown reflects a pro-rated amount of the annualized fixed fee for Mr. Richard's services of $400,000.
(4) 
The amount shown reflects the grant date fair value of the phantom unit awards granted to our NEOs in connection with the consummation of our IPO, as determined in accordance with the Financial Accounting Standards Board ASC Topic 718 (excluding the effect of estimated forfeitures).

Outstanding Equity Awards at Fiscal Year-End 2013

This table shows outstanding equity awards for the NEOs under the LTIP. All values are shown as of December 31, 2013.

 
 
Unit Awards
 
 
Phantom Units
Name
 
Units that have not Vested(1)
 
Market Value of Units that have not Vested(2)
Charles B. Stanley
 
10,000

 
$
232,200

Richard J. Doleshek
 
7,500

 
174,150

Perry H. Richards
 
2,500

 
58,050

            
(1) 
The Phantom Units were granted on August 14, 2013, with distribution equivalent rights and vest in three equal, annual installments commencing on September 5, 2014. The holder forfeits all phantom units that have not vested if there is a separation of employment.
(2)  
The market value is based on the closing market price of a common unit on December 31, 2013 of $23.22 per unit.

Compensation Committee Interlocks and Insider Participation

As previously discussed, the Board is not required to maintain, and does not maintain, a compensation committee. Messrs. Stanley, Doleshek and Richards, who are directors of our General Partner, are also executive officers of QEP. However, all compensation decisions with respect to each of these persons are made by QEP and none of these individuals receives any compensation directly from us or our General Partner except for phantom units under our LTIP. Please read Certain Relationships and Related Transactions and Director Independence below for information about relationships among us, our General Partner and QEP.

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Elements of Compensation

Base Compensation. The NEOs earn a base salary for their services to QEP and to us, which is paid by QEP. We incur only a fixed expense per month that we pay QEP for the services of each of the NEOs under the terms of the Omnibus Agreement and does not reflect amounts actually paid to the NEOs by QEP. As of December 31, 2013, the annualized fixed fee for each of the NEOs is as follows: for Mr. Stanley, $650,000; for Mr. Doleshek, $350,000; and for Mr. Richards, $400,000.

Annual Cash Incentive Plan. The NEOs are eligible to earn an annual incentive payment under QEP's Annual Incentive Program. The amount of any annual incentive payment to the NEOs will be determined generally based upon their performance with respect to their services provided to QEP and its subsidiaries, which may, directly or indirectly, include a component that relates to our financial performance or their services with respect to our business. However, any incentive payment made to the NEOs will be determined solely by QEP without input from us or the Board. No portion of any incentive paid by QEP for the NEOs will be charged back to us under the provisions of the Omnibus Agreement.

Long-Term Incentive Compensation. In connection with the Offering, the Board adopted the QEP Midstream Partners, LP 2013 Long-Term Incentive Plan (the LTIP) for officers, directors and employees of the General Partner or its affiliates, and any consultants, affiliates of the General Partner or other individuals who perform services for the Partnership. The Partnership reserved 5,341,000 common units for issuance pursuant to and in accordance with the LTIP.

The LTIP provides for the grant, from time to time at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the LTIP to 5,341,000 common units. Common units cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the Board.

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

In 2013, the Board granted awards of phantom units with distribution equivalent rights under the LTIP to certain key employees who provide services to us, including each of the NEOs. The phantom units granted entitle the grantee to receive common units upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the Board, cash equal to the fair market value of a common unit. These phantom units granted are payable in common units and vest in three equal annual installments commencing the anniversary of the consummation of the IPO. The phantom units also vest in full in the event the recipient dies or becomes disabled or upon the occurrence of a change in control of the Partnership or QEP. The phantom unit awards were made to reward each recipient for their service in connection with the IPO and to align the recipient’s interests with those of our unitholders. The number of phantom units granted to each recipient was determined based on a targeted value for the award and the price per unit in the IPO. We also granted distribution equivalent rights in tandem with the awards of phantom units. These distribution equivalent rights are rights to receive an amount in cash equal to all of the cash distributions made on common units during the period the awards remain outstanding.

The NEOs also participate in the equity compensation programs of QEP. All determination with respect to such programs, both now and in the future, will be made by QEP and its subsidiaries without input from us or our General Partner, or the Board. QEP bears the full cost of any such programs and no portion of these benefits are charged back to us under the provisions of the Omnibus Agreement.

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Benefit Programs and Perquisites. Neither we nor our General Partner sponsor any benefit plans, programs, or policies such as healthcare, life, income protection or retirement benefits for the NEOs, and neither we nor our General Partner provide our NEOs with any perquisites. However, such benefits are generally provided to our NEOs in connection with their employment by QEP and its subsidiaries and are based on the eligibility provisions contained in their various plan documents. All determinations with respect to such benefits, both now and in the future, will be made by QEP and its subsidiaries without input from us or our General Partner or its Board of Directors. QEP bears the full cost of any such programs and no portion of these benefits are charged back to us under the provisions of the Omnibus Agreement.

Potential Payments Upon Termination of Employment or Change in Control. Except with respect to the termination and change in control provisions of the NEOs' phantom unit awards, as described above, the NEOs are not parties to any agreements or arrangements with us pursuant to which they would receive any payments or benefits in connection with a termination of their employment or a change in control of us or our General Partner. With respect to any future awards under our LTIP, the consequences of a change in control or the termination of a grantee's employment or other service arrangement with us will generally be determined by the plan administrator in terms of the relevant award agreement. With respect to their services to QEP, our NEOs participate in executive severance arrangements maintained by QEP; however, we would incur no obligation in relation to such arrangements.

Other Policies. In order to ensure that executive officers or our General Partner, including the NEOs, bear the full risks of our common unit ownership, our executive officers are subject to a policy that prohibits hedging transactions related to our units or pledging or creating a security interest in any of our units.

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

Director Compensation

The officers or employees of our General Partner or of QEP who also serve as directors of our General Partner will not receive additional compensation for their service as a director of our General Partner. Directors of our General Partner who are not officers or employees of our General Partner or of QEP will receive compensation as "non-employee directors."

Each of our non-employee directors receives a compensation package having an annual value equal to $130,000 and payable as follows:
•
50.0% in the form of a cash retainer, payable in equal quarterly installments of $16,250; and
•
50.0% in the form of an annual award of common units granted under the LTIP.

We have established ownership guidelines for our non-employee directors with the goal of promoting ownership of our units and aligning the interests of our directors with those of our unitholders. The guidelines require non-employee directors to hold five times their annual cash retainer in QEPM units within five years of the date the person first becomes a director.

Upon their commencement of service with us, each non-employee director received a prorated retainer reflecting their partial year of service with us in 2013 and a common unit award.

In addition, the chair of each standing committee of the Board receives an additional annual retainer, payable in cash as follows:
•
Audit Committee Chair - $10,000
•
Conflicts Committee Chair - $10,000

Further, each director is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law and is reimbursed for all expenses incurred in attending to his or her duties as a director.


105


2013 Director Compensation Table

Amounts reflected in the table below represent compensation paid for the period August 14, 2013 to December 31, 2013.

Name
 
Fees Earned or Paid in Cash (1)
 
Unit Awards (2)
 
Total
Susan O. Rheney
 
$
31,250

 
$
71,598

 
$
102,848

Don A. Turkleson
 
10,833

 
65,010

 
75,843

Gregory C. King
 
12,500

 
65,010

 
77,510

            
(1) 
The amounts shown in this column reflect the director cash retainers and committee chair fees paid for board service based on when the service was effective. Ms. Rheney's service was effective June 28, 2013, and Mr. Turkleson's and Mr. King's service was effective November 1, 2013.
(2)
The amounts shown in this column reflect the aggregate grant date fair value, as determined in accordance with FASB ASC Topic 718 (excluding the effect of estimated forfeitures) for awards of common units as follows: Rheney – 3,250 units; Turkleson – 2,874 units; and King – 2,874 units.


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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

The following table sets forth the beneficial ownership of our common units and other classes of equity as of December 31, 2013 (unless otherwise noted) of each person or group of persons known to be a beneficial owner of 5% or more of our then outstanding units. Beneficial ownership generally includes those units held by someone who has investment and/or voting authority over such units or has the right to acquire such units within 60 days. The ownership includes units that are held directly and also units held indirectly through a relationship, a position as a trustee, or under a contract or understanding.
 
 
Units Beneficially Owned
 
 
Common Units
 
Subordinated Units
 
General Partner Units
 
 
Name and Address of Beneficial Owner

Number

Percent

Number

Percent

Number
 
Percent
 
Total Partnership Interests
QEP Resources, Inc. (1)
 
3,701,750

 
13.9
%
 
26,705,000

 
100
%
 
1,090,117

 
100
%
 
56.9
%
1050 17th Street, Suite 500
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denver, CO 80265
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Janus Capital Management LLC(2)
 
1,848,559

 
6.9
%
 
—

 
—

 
 
 
 
 
3.5
%
151 Detroit Street
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denver, CO 80206
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Harvest Fund Advisors(3)
 
1,753,123

 
6.5
%
 
—

 
—

 
 
 
 
 
3.3
%
100 West Lancaster Avenue, Suite 200
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Wayne, PA 19087
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Kayne Anderson Capital Advisors, LP(4)
 
1,691,700

 
6.3
%
 
—

 
—

 
 
 
 
 
3.2
%
Richard A. Kayne
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1800 Avenue of the Stars, Third Floor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Los Angeles, CA 90067
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Invesco, Ltd.(5)
 
1,572,519

 
5.9
%
 
—

 
—

 
 
 
 
 
2.9
%
1555 Peachtree St., N.E., Suite 1800
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Atlanta, GA 30309
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ClearBridge Investments(6)
 
1,369,655

 
5.1
%
 
—

 
—

 
 
 
 
 
2.6
%
620 Eighth Ave, 48th Floor
 
 
 
 
 
 
 
 
 
 
 
 
 
 
New York, New York 10018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
            
(1) 
QEP is the parent company of QEP Field Services, the sole owner of the member interests of our General Partner. QEP Field Services is the owner of 3,701,750 common units and 26,705,000 subordinated units. QEP may, therefore, be deemed to beneficially own the units held by QEP Field Services.
(2) 
According to a Schedule 13G filed on February 14, 2014, Janus Capital Management LLC has shared voting and dispositive power over 1,848,559 of our Common Units.
(3) 
According to a Schedule 13G filed on February 12, 2014, Harvest Fund Advisors, LLC has sole voting and dispositive power over 1,753,123 of our Common Units.
(4) 
According to a Schedule 13G filed on February 5, 2014, Kayne Anderson Capital Advisors, LP and Richard A. Kayne have shared voting and dispositive power over 1,691,700 of our Common Units.
(5) 
According to a Schedule 13G filed on February 11, 2014, Invesco, Ltd. has sole voting power over 1,211,419 of our Common Units, and sole dispositive power over 1,572,519 of our Common Units.
(6) 
According to a Schedule 13G filed on February 14, 2014, ClearBridge Investments has sole voting and dispositive power over 1,369,655 of our Common Units.
 

107


Directors and Executive Officers

The following table lists the units of our common units beneficially owned as of February 28, 2014 by (i) each member of the Board; (ii) each NEO; (iii) all directors and executive officers of the General Partner as a group. The address of the persons listed below is c/o QEP Resources, Inc., 1050 17th Street, Suite 500, Denver, Colorado 80265.
Name and Address of Beneficial Owner
 
Common Units Beneficially Owned(1)
 
Percentage of Total Outstanding
Charles B. Stanley
 
—

 
*
Richard J. Doleshek
 
—

 
*
Perry H. Richards
 
—

 
*
S. Scott Gutberlet
 
—

 
*
Susan O. Rheney
 
3,250

 
*
Don A. Turkleson
 
2,874

 
*
Gregory C. King
 
2,874

 
*
All Directors and Executive Officers as a group (seven reporting persons)
 
8,998

 
*
            
*The percentage of units beneficially owned by each director does not exceed 1% of the common units and subordinated units outstanding
(1)
None of the units shown in this table have been pledged as a security.

The following table sets forth the number of shares of QEP common stock beneficially owned as of March 7, 2014, except as otherwise noted, by each director, by each named executive officer and by all directors and executive officers of our general partner as a group:
 
  
 
Amount and Nature of
Beneficial Ownership
 
 
 
 
Name of Beneficial Owners
 
Common Stock
Beneficially
Owned
 
 
 
Common Stock
Acquirable
within 60
Days
 
Total
Beneficially
Owned
 
 
 
Percent of Total
Outstanding
Directors/Named Executive Officers
 
 
 
 
 
 
 
 
 
 
 
 
Charles B. Stanley
 
544,102

 
(1) 
 
383,939

 
928,041

 
(1) 
 
*
Richard J. Doleshek
 
159,369

 
(2) 
 
206,305

 
365,674

 
(2) 
 
*
Perry H. Richards
 
50,843

 
(3) 
 
62,432

 
113,275

 
(3) 
 
*
S. Scott Gutberlet
 
23,323

 
(4) 
 
2,902

 
26,225

 
(4) 
 
*
Susan O. Rheney
 
—

 
 
 
—

 
—

 
 
 
*
Don A. Turkleson
 
—

 
 
 
—

 
—

 
 
 
*
Gregory C. King
 
—

 
 
 
—

 
—

 
 
 
*
All Directors and Executive Officers as a group (seven persons)
 
777,637

 
  
 
655,578

 
1,433,215

 
  
 
*
             
*The percentage of shares owned is less than 1%. The percentages of beneficial ownership have been calculated in accordance with Rule 13d-3(d)(1) under the Exchange Act.
(1) 
Includes 13,368 equivalent shares of stock held for Mr. Stanley’s account in the QEP Resources, Inc. Employee Investment Plan (QEP 401(k) Plan), and 101,796 shares of unvested restricted stock, with respect to which he receives dividends and has voting power, but which cannot be disposed of until they vest. Some of the vested shares listed for Mr. Stanley are held in a family trust, of which he and his wife are trustees. Excludes 119,907 shares owned by the QEP

108


Resources Educational Foundation, a nonprofit corporation. As chairman of the Board of Trustees of the Foundation, Mr. Stanley has voting power for such shares. Mr. Stanley disclaims any beneficial ownership of these shares.
(2) 
Includes 1,209 equivalent shares of stock held for Mr. Doleshek’s account in the QEP 401(k) Plan, and 51,368 shares of unvested restricted stock, with respect to which he receives dividends and has voting power, but which cannot be disposed of until they vest.
(3) 
Includes 6,838 equivalent shares of stock held for Mr. Richards’ account in the QEP 401(k) Plan, and 13,016 shares of unvested restricted stock, with respect to which he receives dividends and has voting power, but which cannot be disposed of until they vest.
(4) 
Includes 1,633 equivalent shares of stock held for Mr. Gutberlet’s account in the QEP 401(k) Plan, and 11,289 shares of unvested restricted stock, with respect to which he receives dividends and has voting power, but which cannot be disposed of until they vest.

Securities Authorized for Issuance under Equity Compensation Plan

The following table sets forth information with respect to the securities that may be issued under the LTIP as of December 31, 2013. For more information regarding the LTIP, which did not require approval by our unitholders, please see Item 11 of Part III of this Annual Report on Form 10-K.

Plan Category
 
Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights(2)
 
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights
 
Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans
Equity compensation plans approved by security holders
 
38,250

 
—

 
5,293,752

Equity compensation plans not approved by security holders (1)
 
—

 
—

 
—

            
(1)
The Board adopted the LTIP in August 2013.
(2) 
Represents phantom unit awards granted under our LTIP. Phantom units have no applicable exercise price.



109


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Party Transactions

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of December 31, 2013, QEP Field Services owns 3,701,750 common units and 26,705,000 subordinated units representing a 55.8% limited partner interest in us. In addition, our General Partner owns 1,090,117 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEP Field Services and QEP are considered to be related party transactions because our General Partner and its affiliates own more than 5% of our equity interests. In addition, Messrs. Stanley, Doleshek, Richards and Gutberlet all serve as officers of both QEP and our General Partner.

Initial Public Offering and Related Structuring Transactions

On August 14, 2013, in connection with the closing of the IPO, the Partnership entered into the Contribution Agreement with QEP Field Services, the General Partner and the Operating Company. Immediately prior to the closing of the IPO, the following transactions, among others, occurred pursuant to the Contribution Agreement:

•
QEP Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2% of the equity value of the Partnership at the closing of the IPO;
•
the General Partner contributed to the Partnership, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2% general partner interest in the Partnership and (b) all the incentive distribution rights of the Partnership;
•
QEP Field Services contributed to the Partnership, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in the Partnership, (b) 26,705,000 subordinated units representing a 49% limited partner interest in the Partnership and (c) the right to receive a distribution from the Partnership; and
•
the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to the Partnership in exchange for the issuance of 20,000,000 common units.

Subsequent to the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units in the Partnership, which reduced QEP Field Services' common unit interest in the Partnership from 12.3% to 6.8%. As a result of the IPO, the Partnership received net proceeds of $449.6 million which were used to repay long-term debt to QEP of $95.5 million, pay revolving credit origination fees of $3.0 million and make a cash distribution to QEP for $351.1 million.

Distributions of Available Cash to our General Partner and its Affiliates

We will generally make cash distributions of 98.0% to the unitholders pro rata, including QEP, as holder of the aggregate of 3,701,750 common units and 26,705,000 subordinated units, and 2.0% to our General Partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our General Partner will entitle our General Partner to increasing percentages of the distribution, limited to 48.0% of the distribution above the highest target distribution level. During the period from August 14, 2013, through December 31, 2013, the Partnership declared distributions totaling $21.3 million, or $0.39 per unit.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our General Partner and its affiliates will receive an annual distribution of approximately $1.1 million on the 2.0% general partner interest and $30.4 million on their common and subordinated units.

Under our Partnership Agreement, we are required to reimburse our General Partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our Omnibus Agreement (described below), our General Partner determines the amount of these expenses and such determinations must be made in good faith in accordance with the terms of the Partnership Agreement.

Omnibus Agreement

On August 14, 2013, in connection with the closing of the IPO, the Partnership entered into the Omnibus Agreement with QEP Field Services, the General Partner, the Operating Company and QEP, which addresses the following matters:


110


•
the Partnership's payment of an annual amount to QEP, initially in the amount of $13.8 million, for the provision of certain general and administrative services by QEP to the Partnership, including a fixed annual fee of approximately $1.4 million for executive management services provided by certain officers of the General Partner, who are also executives of QEP. The remaining portion of this annual amount reflects an estimate of the costs QEP will incur in providing the services;
•
the Partnership's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and its affiliates that are reimbursed under the Partnership's Partnership Agreement), as well as any other out-of-pocket expenses incurred by QEP on the Partnership's behalf; and
•
an indemnity by QEP for certain environmental and other liabilities, and the Partnership's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of the Partnership's assets that occur after the closing of the IPO.

For the period from August 14, 2013, through December 31, 2013, the Partnership was charged $4.6 million under the Omnibus Agreement by QEP. Further, the Partnership received $9.6 million from QEP pursuant the indemnification provisions of the Omnibus Agreement for capital expenditures incurred by the Partnership for a pipeline repair project.

Gathering Agreements

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

For the period from January 1, 2013, through August 13, 2013, and the period from August 14, 2013, through December 31, 2013, revenue from QEP was $51.3 million and $30.8 million respectively, under these gathering agreements.

Acreage Dedication
Several of our gathering agreements with QEP contain acreage dedications. Pursuant to the terms of these agreements, QEP has dedicated to us all of the oil and natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems and located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering agreement and located within the dedicated acreage as our gathering systems currently exist and as they are expanded to connect to additional wells.

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

If QEP’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract year. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. To the extent that QEP’s actual throughput volumes exceed its minimum volume commitment for the applicable period, there is a crediting mechanism that allows QEP to build a “bank” of credits that it can utilize in the future to reduce deficiency payments owed in subsequent periods, subject to expiration if there is no deficiency payment owed in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, ranging from the subsequent minimum volume commitment year to the full term of the agreement.

Condensate Sales Agreements
In connection with the IPO, the Partnership entered into a fixed price condensate purchase agreement with QEP, which requires us to sell and QEP to purchase all of the condensate volumes collected on our gathering systems at a fixed price of $85.25 per barrel of product over a primary term of five years. For the Post-IPO Period, all of our condensate sales were with QEP, which accounted for 4% of our total revenue.


111


Procedures for Review Approval and Ratification of Related Party Transactions

The Board adopted a Related Party Transactions Policy in connection with the closing of the IPO providing that the Board or its authorized committee review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the Board or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

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

The Related Party Transactions Policy described above was adopted in connection with the IPO, and as a result the transactions described above were not reviewed under such policy.

Director Independence

The information appearing under Item 10. Directors, Executive Officers and Corporate Governance - Director Independence, is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Aggregate fees for professional services rendered for the Partnership by PricewaterhouseCoopers LLP for the year ended December 31, 2013, are presented in the following table. The Partnership was formed in April 2013.

(in millions)
2013
Audit fees
$
0.5

Audit-related fees
—

Tax fees
—

All other fees
—

Total
0.5


The audit fees for the year ended December 31, 2013, were for professional services rendered for the post-formation audit of the financial statements. Total audit fees of $0.9 million were incurred during 2013 prior to the IPO and were paid for by QEP.

The Audit Committee has considered whether PricewaterhouseCoopers LLP is independent for purposes of providing external audit services to the Partnership, and the Audit Committee has determined that it is.

Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services

The Audit Committee has adopted procedures for pre-approving all audit and non-audit services provided by its independent accounting firm. These procedures include reviewing fee estimates for audit services and permitted recurring non-audit services, and authorizing the Partnership to execute letter agreements setting forth such fees. Audit Committee approval is required for any services to be performed by the independent accounting firm that are not specified in the letter agreements. The Audit Committee has delegated approval authority to the chairman of the Audit Committee, but any exercises of such authority are reported to the Audit Committee at the next meeting. All fees paid to PwC for the Post-IPO period were pre-approved by the Audit Committee in accordance with this policy.


112


PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial statements and financial statement schedules filed as part of this report are listed in the index included in Item 8. Financial Statements and Supplementary Data of this report.

(b) Exhibits. The following is a list of exhibits required to be filed as a part of this report in Item 15(b).
 
Exhibit No.
 
Exhibits
3.1
 
Certificate of Limited Partnership of QEP Midstream Partners, LP, incorporated by reference to Exhibit 3.1 to the Partnership's Registration Statement on Form S-1, filed with the Securities and Exchange Commission on August 16, 2013.
3.2
 
First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP, dated August 16, 2013, by and between QEP Midstream Partners GP, LLC and QEP Field Services Company, incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.1*
 
QEP Midstream Partners, LP 2013 Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 13, 2013.
10.2*
 
Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Phantom Unit Agreement, incorporated by reference to Exhibit 10.4 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013.
10.3*
 
Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Common Unit Agreement, incorporated by reference to Exhibit 10.13 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 29, 2013.
10.4
 
Contribution, Conveyance and Assumption Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.5*
 
Omnibus Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Resources, Inc., QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.2 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.6
 
Credit Agreement, dated as of August 14, 2013, among QEP Midstream Partners Operating, LLC, as the borrower, QEP Midstream Partners, LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto, incorporated by reference to Exhibit 10.3 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.7
 
Gas Gathering Agreement, dated September 1, 1993, between Questar Gas Company (f/k/a Mountain Fuel Supply Company) and QEP Field Services Company (f/k/a Questar Pipeline Company), incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013, as amended by Amendment to the Gas Gathering Agreement, dated February 6, 1998, between Questar Gas Company and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.7 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013.

113


10.8
 
Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.8 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013, as amended by (i) First Amendment, dated March 1, 2006, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.9 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (ii) Second Amendment, dated August 16, 2007, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.10 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (iii) Third Amendment, dated March 2, 2010, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.11 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; and (iv) Fourth Amendment, dated July 1, 2011, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.12 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013. Certain portions of the Amended and Restated Gas Gathering Agreement, the First Amendment, the Third Amendment and the Fourth Amendment have been omitted pursuant to a confidential treatment request granted by the Securities and Exchange Commission.
10.9*
 
Form of Indemnification Agreement for directors and officers, incorporated by reference to Exhibit 10.9 to the Company's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 8, 2013.
21.1**
 
Subsidiaries of the Partnership.
23.1**
 
Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP - QEP Midstream Partners, LP Predecessor
23.2**
 
Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP - QEP Midstream Partners, LP
24**
 
Power of Attorney
31.1**
 
Certification signed by C. B. Stanley, QEP Midstream Partners, LP's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2**
 
Certification signed by Richard J. Doleshek, QEP Midstream Partners, LP's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
 
Certification signed by C. B. Stanley and Richard J. Doleshek, QEP Midstream Partners, LP's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS+
 
XBRL Instance Document
101.SCH+
 
XBRL Schema Document
101.CAL+
 
XBRL Calculation Linkbase Document
101.LAB+
 
XBRL Label Linkbase Document
101.PRE+
 
XBRL Presentation Linkbase Document
101.DEF+
 
XBRL Definition Linkbase Document
 ____________________________
*
Management contract or compensatory plan or agreement.
**
Filed herewith
+ These interactive data files are furnished and deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Act of 1934, as amended, and otherwise are not subject to liability under those sections.

114


(c) Financial Statement Schedule:

QEP MIDSTREAM PARTNERS, LP
Schedule of Valuation and Qualifying Accounts

Description
 
Beginning Balance
 
Amounts charged (credited) to expense
 
Deductions/Settlements
 
Ending Balance
 
 
(in millions)
Period From August 14, 2013, through December 31, 2013 (Successor)
 
 
 
 
 
 
 
 
Allowance for bad debts
 
$
—

 
$
—

 
$
—

 
$
—

Period From January 1, 2013, through August 13, 2013 (Predecessor)
 
 
 
 
 
 
 
 
Allowance for bad debts
 
0.4

 
—

 
(0.4
)
 
—

Year ended December 31, 2012 (Predecessor)
 
 
 
 
 
 
 
 
Allowance for bad debts
 
0.3

 
0.1

 
—

 
0.4

Year ended December 31, 2011 (Predecessor)
 
 
 
 
 
 
 
 
Allowance for bad debts
 
0.3

 
—

 
—

 
0.3



115


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 20, 2014.
 
 
QEP MIDSTREAM PARTNERS, LP
 
(Registrant)
 
 
 
By: QEP MIDSTREAM PARTNERS GP, LLC
 
(its General Partner)
 
 
 
/s/ Charles B. Stanley
 
Charles B. Stanley
 
Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on March 20, 2014.
 
/s/ Charles B. Stanley
 
Chairman, President and Chief Executive Officer of QEP Midstream Partners GP, LLC
Charles B. Stanley
 
(Principal Executive Officer)
 
 
 
/s/ Richard J. Doleshek
 
Executive Vice President, Chief Financial Officer, and Treasurer of QEP Midstream
Richard J. Doleshek
 
Partners GP, LLC (Principal Financial Officer)
 
 
 
/s/ Alice B. Ley
 
Vice President, Controller, and Chief Accounting Officer of QEP Midstream Partners GP, LLC
Alice B. Ley
 
(Principal Accounting Officer)
 
 
 
*Charles B. Stanley
 
Chairman of the Board; Director of QEP Midstream Partners GP, LLC
*Richard J. Doleshek
 
Director of QEP Midstream Partners GP, LLC
*Perry H. Richards
 
Director of QEP Midstream Partners GP, LLC
*S. Scott Gutberlet
 
Director of QEP Midstream Partners GP, LLC
*Susan O. Rheney
 
Director of QEP Midstream Partners GP, LLC
*Don A. Turkleson
 
Director of QEP Midstream Partners GP, LLC
*Gregory C. King
 
Director of QEP Midstream Partners GP, LLC
 
 
 
March 20, 2014
*By
/s/ Charles B. Stanley
 
 
Charles B. Stanley, Attorney in Fact


116