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, 2014



	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.)

19100 Ridgewood Pkwy, San Antonio, Texas 78259-1828

(Address of principal executive offices)

210-626-6000

(Registrant’s telephone number, including area code)

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 June 30, 2014, the aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $592.7 million based upon the closing price of its common units on the New York Stock Exchange Composite tape. At March 2, 2015, there were 26,741,330 common units, 26,705,000 subordinated units and 1,090,495 general partner units outstanding.

QEP Midstream Partners, LP

Form 10-K for the Year Ended December 31, 2014

TABLE OF CONTENTS



		Page
Where You Can Find More Information		2
Forward-Looking Statements		2
Glossary of Terms		4
PART I
ITEMS 1 AND 2.	BUSINESS AND PROPERTIES	6
ITEM 1A.	RISK FACTORS	25
ITEM 1B.	UNRESOLVED STAFF COMMENTS	35
ITEM 3.	LEGAL PROCEEDINGS	35
ITEM 4.	MINE SAFETY DISCLOSURES	35
PART II
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	36
ITEM 6.	SELECTED FINANCIAL DATA	39
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	42
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	62
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	63
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	86
ITEM 9A.	CONTROLS AND PROCEDURES	86
ITEM 9B.	OTHER INFORMATION	87
PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERANCE	88
ITEM 11.	EXECUTIVE COMPENSATION	93
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	98
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS AND DIRECTOR INDEPENDENCE	102
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	104
PART IV
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	106
	SIGNATURES	109

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 Resources” refers to QEP Resources, Inc. (NYSE: QEP) and its consolidated subsidiaries and “TLLP” refers to Tesoro Logistics LP (NYSE: TLLP) and its consolidated subsidiaries.

Where You Can Find More Information

QEP Midstream 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 IPO that occurred on August 14, 2013. QEP Midstream 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 and Code of Business Conduct and Ethics.

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, 19100 Ridgewood Pkwy, San Antonio, Texas 78259-1828 (telephone number: 1-210-626-6000).

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 actual results of operation of our Predecessor as a standalone entity and our future results;


•	favorable terms of related party agreements;


•	fees charged for firm service and the steadiness of revenues from fee-based agreements;


•	seasonality of our business;


•	estimated amounts and allocation of capital expenditures;


•	factors affecting the comparability of our operating results;


•	reasonableness of the methodologies for allocating general and administrative costs of our Predecessor;


•	estimates of contingency losses and the outcome of pending litigation and other legal proceedings;


•	drilling activity on dedicated acreage and its impact on throughput levels and production;


•	correlation of drilling activity with commodity prices and production levels;


•	impact of growth capital expenditures on operating capacity and income;


•	ability to negotiate contractual terms to generate an acceptable rate of return;


•	the timing, terms or potential structure of the proposed combination of the Partnership and TLLP;


•	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;


•	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;


•	acquisitions of additional midstream assets from QEP Field Services, LLC (“QEPFS”) 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;


•	amount, funding and timing of future cash distributions;


•	variance of growth capital expenditures from period to period;


•	funding for acquisition and growth capital expenditures;


•	sources of liquidity;


•	sufficiency of cash provided by operating activities, borrowings under our affiliate credit agreement 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 Resources and Questar Gas Company’s (“QGC”), as our largest customers, failure to perform under the terms of our gathering agreements;


•	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 the IPO;


•	supplemental pro forma disclosures;


•	exposure to commodity price risks;


•	estimated amounts and timing of distributions; and


•	impact of recent accounting developments.

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 our actual results to differ materially include, but are not limited to, the following:


•	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 potential failure to complete the proposed combination with Tesoro Logistics LP;


•	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;


•	labor relations;


•	large customer defaults;


•	changes 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.

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.

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.

bpd Barrels per day.

Btu One British thermal unit — a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

cf Cubic foot or feet is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard temperature (60 degrees Fahrenheit) and standard pressure (14.73 pounds standard per square inch).

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.

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

MBbls One thousand barrels.

Mbpd 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.

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.

FORM 10-K

ANNUAL REPORT 2014

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

As used in this document, unless the context otherwise indicates, the terms “we,” “us,” “our,” and “the Partnership” mean QEP Midstream, one or more of our operating subsidiaries, or all of them as a whole. Unless the context otherwise requires, references to Tesoro Logistics LP (“TLLP”) refer collectively to TLLP and its subsidiaries, other than QEP Midstream, its subsidiaries and its general partner, QEP Midstream Partners GP, LLC (our “General Partner”). In August 2013, we completed the IPO of 23.0 million common units representing limited partner interests.

Overview

We are a master limited partnership formed 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. In addition, on July 1, 2014, the Partnership acquired a 40% interest in Green River Processing, LLC (“Green River Processing”), from QEP Field Services Company (“QEPFSC”) for $230.0 million (the “Green River Processing Acquisition”). The Green River Processing Acquisition was funded with $220.0 million of borrowings under the Partnership’s $500.0 million revolving credit facility (the “Prior Credit Facility”) and cash on hand. 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, 2014, our gathering systems had 1,510 miles of pipeline. We believe our customers are some of the largest natural gas producers in the Rocky Mountain region.

On December 2, 2014, the midstream business of QEP Resources, Inc. (“QEP Resources”) was acquired by TLLP, which included all of the issued and outstanding membership interest of QEP Field Services, LLC (“QEPFS”), a wholly-owned subsidiary of QEPFSC formed for purposes of consummating the QEP Field Services acquisition, pursuant to the Membership Interest Purchase Agreement, dated as of October 19, 2014, by and between TLLP and QEPFSC. QEPFS is the owner of QEP Midstream’s general partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights. The acquisition also included an approximate 56% limited partner interest in the Partnership (collectively, the “Acquisition”). Prior to the Acquisition, QEPFSC owned and operated QEP Midstream’s general partner. This resulted in a change of control of the Partnership’s general partner and the Partnership became a consolidated subsidiary of TLLP on the acquisition date. The transaction included consideration of $230.0 million paid by TLLP to refinance the Partnership’s debt outstanding under the Prior Credit Facility. The transaction did not involve the sale or purchase of any QEP Midstream common units held by the public. Prior to this transaction, QEP Resources, through its wholly-owned subsidiary, QEPFSC, served as the Partnership’s general partner and owned a 2% general partner interest, all of the Partnership’s incentive distribution rights and an approximate 56% limited partner interest in the Partnership.

On December 2, 2014, TLLP delivered a letter to the board of directors of our General Partner (the “Board”) in which it made a non-binding proposal to merge a wholly-owned subsidiary of TLLP with the Partnership (the “Proposed Merger”). The Proposed Merger would occur in a unit-for-unit exchange at a ratio of 0.2846 TLLP common units for each outstanding QEPM common unit. The terms of any such combination have not been fully negotiated, and it will be subject to a review and approval of the Board, the board of directors of TLLP’s general partner (“TLGP”), the conflicts committee of the Board and the QEPM unitholders. The Partnership cannot predict whether the terms of a potential combination will be agreed upon by the Board, the TLGP board of directors, the conflicts committee of the Board or the unitholders of QEPM, the timing or final structure of any potential agreement, if any. TLLP’s goal is to complete the transaction during 2015.

We provide all of our gathering services through fee-based agreements, the majority of which have annual inflation adjustment mechanisms. As of December 31, 2014, approximately 81% of our revenues were generated pursuant to contracts with remaining terms in excess of five years, including 60% 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 per barrel. For the year ended December 31, 2014, approximately 67% of our revenue came from QEP Resources, making QEP Resources our largest customer.

2014 Financial and Operating Highlights

Financial and operating highlights for the year ended December 31, 2014 include:


•	Generated $123.2 million of revenue, $50.0 million of net income, $88.7 million of Adjusted EBITDA and $72.4 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 first quarter 2014 distribution of $0.27 per unit, a second quarter 2014 distribution of $0.28 per unit, a third quarter 2014 distribution of $0.30 per unit and a fourth quarter 2014 distribution of $0.31 per unit; and


•	Had average gross throughput of 1.7 million MMBtu/d of natural gas, 15,787 bpd of crude oil and 13,688 bpd of water, and sold 62.4 Mbbls of condensate.

Organizational Structure

The following table and diagram illustrate our ownership and organizational structure as of December 31, 2014:



	Ownership Interest
Common units held by the public	42.2	%
Common units held by TLLP	6.8	%
Subordinated units held by TLLP	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.

Initial Public Offering

On August 14, 2013, the Partnership completed its IPO. As part of the IPO, QEP Midstream Partners GP, LLC and QEPFSC, collectively contributed to the Partnership a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the “Operating Company”), QEPM Gathering I, LLC and Rendezvous Pipeline Company, LLC (“Rendezvous Pipeline”), a 78% interest in Rendezvous Gas Services, L.L.C. (“Rendezvous Gas”), and 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 TLLP, provides services to the Partnership pursuant to the First Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”), entered into in connection with the Acquisition. The Amended Omnibus Agreement, dated December 2, 2014, amended and restated the Omnibus Agreement dated August 14, 2013, (the “Original Omnibus Agreement”), entered into in connection with the closing of the IPO.

Business Strategies

Our principal business objectives include the following:

•

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. 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 considering acquisition and development opportunities in new geographic areas. In addition to our existing areas of operations, we will consider diversifying our midstream business and expanding our platform for future growth through acquisition and greenfield development opportunities in geographic regions where we currently do not operate.

•

Maintaining our financial flexibility. We expect to maintain a capital structure using appropriate amounts of debt and equity financing. On December 2, 2014, in connection with the Acquisition, we entered into a $500.0 million unsecured, affiliate credit agreement (the “Affiliate Credit Agreement”).We believe that our Affiliate Credit Agreement, our ability to issue additional partnership units and long-term debt, and our relationships with TLLP and our existing joint venture partners will provide us with the financial flexibility to execute our business strategy.

•

Minimizing direct commodity price exposure. We intend to maintain our focus on providing midstream services under fee-based agreements. We have a fixed price condensate purchase agreement with QEPFS 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. Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into a five-year agreement with Tesoro Refining & Marketing Company LLC, a wholly-owned subsidiary of Tesoro Corporation (“TRMC”), which transfers Green River Processing’s commodity risk exposure associated with keep-whole processing agreements to TRMC (the “Keep-Whole Commodity Agreement”). Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a BTU content equivalent to the NGLs removed. The operating margin for these contracts is determined by the spread between NGL sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). Under the Keep-Whole Commodity Agreement with TRMC, TRMC pays Green River Processing a processing fee for NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of Green River Processing. Green River Processing pays TRMC a marketing fee in exchange for assuming the commodity risk.

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 TLLP and QEPFS. On December 2, 2014, TLLP acquired full ownership of QEPFS, the owner of QEP Midstream’s general partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights and a 55.8% limited partner interest in the Partnership. As a result, we believe that TLLP and QEPFS are motivated to promote and support our business plan and to pursue projects that enhance the overall value of our business.

•

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 ownership has changed as a result of the Acquisition. However, our executive management team has experienced operating teams 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, 2014, we had $210.0 million outstanding out of a total borrowing capacity of $500.0 million under our Affiliate Credit Agreement. 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, transportation and processing services to producers and users of natural gas and crude oil. The market we serve, which begins at the point of purchase at the source of production and extends to the point of distribution to the end-user customer, is commonly referred to as the “midstream” market.

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

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

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 2015, petroleum accounted for about 36% of the nation’s total annual energy consumption during 2013. 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:

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.

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.

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 TLLP and QEPFS

One of our strengths is our relationship with TLLP and QEPFS. On December 2, 2014, TLLP acquired full ownership of QEPFS, the owner of QEP Midstream’s general partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights and an approximate 56% limited partner interest in the Partnership. TLLP and QEPFS generate revenues by charging fees for gathering crude oil and natural gas, for terminalling, transporting and storing crude oil and refined products and for processing natural gas for affiliates and third parties.

As the owner of our 2.0% general partner interest, all of our incentive distribution rights, and a 55.8% limited partner interest in us, we believe that QEPFS is motivated to support the successful execution of our business plan and to pursue projects and acquisitions that should enhance the overall value of our business. However, QEPFS 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.

In addition, during 2014, the Partnership acquired 40% of the membership interests in Green River Processing. QEPFS owns the remaining 60% of Green River Processing, which owns two gas processing complexes and one fractionation facility. Refer to additional information regarding Green River Processing on page 15.

We entered into the Original Omnibus Agreement with QEP Resources in connection with the IPO. The Original Omnibus Agreement addressed our payment of fees to QEPFSC for certain general and administrative services and QEP Resources’ and QEPFSC’s indemnification of us for certain matters, including environmental, contractual, title and tax matters. In conjunction with the Acquisition, we entered into the Amended Omnibus Agreement with TLLP’s general partner, TLGP and TLLP which addresses our payment of fees to TLGP for certain general and administrative services and TLLP’s indemnification of us for certain matters, including legal, environmental, title and tax matters associated with the ownership of the assets at or before the closing of the IPO. While not the result of arm’s-length negotiations, we believe the terms of the Amended Omnibus Agreement with TLGP and TLLP are generally no less favorable to any of the parties 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 TLLP and QEPFS and their 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 TLLP’s or QEPFS’ business decisions and operations, and TLLP and QEPFS are under no obligation to adopt a business strategy that favors us.

Our Assets and Operations

Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines. Additionally, we have a 40% interest in two gas processing complexes through the Green River Processing Acquisition. The following tables provide information regarding our assets by system as of and for the year ended December 31, 2014:

Gathering



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	365	298	41,053	737		556
	Oil/Condensate Gathering	134	107	—	7,137	⁽²⁾	3,524	⁽²⁾
	Water Gathering	25	107	—	21,990	⁽²⁾	13,688	⁽²⁾
	Oil/Condensate Transmission⁽³⁾	60	6	—	40,800	⁽²⁾	9,554	⁽²⁾
Rendezvous Gas ⁽⁴⁾	Gas Gathering	311	3	7,800	1,032		661
Rendezvous Pipeline ⁽³⁾	Gas Transmission	21	1	—	450		266
Vermillion Gathering System	Gas Gathering	504	456	23,932	212		111
Three Rivers Gathering System ⁽⁵⁾	Gas Gathering	52	9	4,735	212		58
Williston Gathering System	Gas Gathering	20	31	239	3		2
	Oil Gathering	18	31	—	7,000	⁽²⁾	2,709	⁽²⁾
Total		1,510	1,049	77,759

____________


⁽¹⁾	Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2014.


⁽²⁾	Capacity and throughput measured in bpd.


⁽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 gathers and stabilizes crude oil production from the Pinedale Field, transports the stabilized crude oil to an interstate pipeline interconnect, and 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 Resources, 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.

Rendezvous Pipeline

Rendezvous Pipeline provides gas transportation services from QEPFS’ 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 Resources and Chevron USA, Inc. (“Chevron”). For the year ended December 31, 2014, approximately 50% 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, which was formed to transport natural gas gathered by Uintah Basin Field Services, L.L.C., an equity method investment in which QEPFS owns a 38% interest, and other third-party volumes to gas processing facilities owned by QEP Resources 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., Anadarko Petroleum Corporation (“Anadarko”) and QEP Resources.

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 bpd of crude oil and five thousand MMBtu/d of natural gas from one producer through 2026. QEP Resources and Marathon Oil Company are currently the only customers on our Williston Gathering System.

Processing/Treating/Fractionation

Asset

Primary Location

Asset Type

Facility Type

Throughput Capacity (MMCf/d)⁽¹⁾

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

Blacks Fork Complex⁽²⁾

Green River Basin

Processing

Cryogenic/Joule-Thomson

835

486

Fractionation

Fractionator

15,000

⁽³⁾

9,403

⁽³⁾

Emigrant Trail Complex⁽²⁾

Green River Basin

Processing

Cryogenic

⁽⁴⁾

Total

Processing

890

502

Fractionation

15,000

9,403

____________


⁽¹⁾	Represents 100% of the capacity and throughput of the systems as of and for the year ended December 31, 2014.


⁽²⁾	Our ownership interest in Green River Processing is 40%.


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


⁽⁴⁾	Since May 2014, all Emigrant Trail processing volumes have been temporarily diverted to the Blacks Fork processing complex.

Green River Processing

Blacks Fork Complex

The Blacks Fork Processing Complex consists of three separate gas processing trains located in Sweetwater and Uinta counties, Wyoming. The Blacks Fork Processing Complex is party to a gas conditioning agreement (the “Gas Conditioning Agreement”) with QEP Midstream whereby QEP Midstream has agreed to make available to TLLP at the Blacks Fork Processing Complex natural gas volumes that it has gathered under certain “life-of-reserves” and long-term, natural gas gathering agreements with several producer customers. Pursuant to the terms of the Gas Conditioning Agreement, the Blacks Fork Processing Complex has been assigned QEP Midstream’s conditioning and keep-whole processing rights detailed in the underlying gathering agreements.

Approximately 67% of inlet volumes for the year ended December 31, 2014, were processed under a fee-based agreement with a remaining term of more than 12 years. Approximately 32% of inlet volumes for the year ended December 31, 2014, at the Blacks Fork Processing Complex were processed under the Gas Conditioning Agreement. The primary customers supplying the Blacks Fork Complex include QEP Resources, Ultra Petroleum Corporation and Questar Corporation (“Questar”). The complex receives the majority of its gas from the Pinedale Anticline and the Moxa Arch fields located in the Green River Basin of western Wyoming.

Emigrant Trail Complex

The Emigrant Trail Processing Complex consists of one cryogenic gas processing train located in Uinta County, Wyoming. The complex is supported by fee-based and keep-whole processing agreements. The primary customers supplying the Emigrant Trail Complex include Questar and Anadarko. The complex receives the majority of its gas from various gas fields along the Moxa Arch, including Church Buttes, located in the Green River Basin of western Wyoming. All Emigrant Trail processing volumes have been diverted to the Blacks Fork processing complex since May 2014 .

Competition

The midstream crude oil and natural gas industry is very competitive. Our competitors include other midstream companies, producers and intrastate and interstate pipelines. Competition for 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 our customers under our gathering agreements, we believe that our gathering systems and other midstream assets will not face significant competition from other pipelines or facilities for the crude oil, natural gas or products transportation requirements of our customers.

Seasonality

Our operations are affected by seasonal weather conditions. For example, some of our customers cease completion activity on drilled wells in the Pinedale Field from approximately December through March of each year, 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 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.

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 are covered under insurance policies held by TLLP and it’s sponsor, Tesoro Corporation (“Tesoro”), for which we reimburse TLGP, pursuant to the terms of the Amended Omnibus Agreement. Our property and casualty insurance program includes coverage for physical damage to our properties, third-party liability, pollution, workers’ compensation, auto liability, and employers’ liability. 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 2014, we incurred approximately $0.9 million to complete the testing required by existing Department of Transportation (“DOT”) regulations and their state counterparts. We currently estimate that we will incur approximately $0.6 million in costs during 2015 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.

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.

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.

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

Interstate Pipelines

We own a natural gas pipeline, located in Wyoming, which transports gas to downstream interstate pipelines and is therefore considered to be engaged in interstate commerce. 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 will 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.

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, 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:


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


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


•	delaying system modification or upgrades during permit reviews;


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


•	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 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.

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 (“CEQ”) has announced an intention to reinvigorate NEPA reviews and in March 2012 issued final guidance. In December 2014, the CEQ issued draft guidance on the consideration of greenhouse gas emissions in NEPA reviews. Each of these 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.

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 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.

Hydraulic Fracturing

A majority 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, with the results expected to be available in 2015. 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 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.

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 DHS, 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.

Significant Customers

The Partnership’s five largest customers accounted for 91% in aggregate of QEP Midstream’s revenues for the year ended December 31, 2014. 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, 2014, QEP Resources accounted for 67% of the Partnership’s total revenues and QGC accounted for 15% 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. 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, 2014, the General Partner and its affiliates have approximately 200 employees performing services for our operations. We believe that our General Partner and its affiliates have a satisfactory relationship with those employees.

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

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


•	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, natural gas and NGL prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our assets. Increases in natural gas prices and decreases in NGL prices could impact processing margins.

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

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 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 five customers accounted for over 90% of our revenue for the year ended December 31, 2014. We have gathering contracts with each of these customers of varying duration and commercial terms. If we were unable to renew our contracts with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. QEP Resources and QGC accounted for approximately 67% and 15%, respectively, of our revenue for the year ended December 31, 2014. 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.

Although the Acquisition is Completed, a Combination With TLLP May Not Be Consummated. Following the closing of the Acquisition on December 2, 2014, TLLP submitted a proposal to the conflicts committee of the Board to combine TLLP and the Partnership in a unit-for-unit exchange. The terms of any such combination have not been fully negotiated, and we expect that it will be subject to the review and approval of the board of TLGP, the conflicts committee of the Board and the Partnership’s common unitholders. We cannot predict whether the terms of a potential combination will be agreed upon by the board of TLGP, the conflicts committee of the Board or approved by the Partnership’s common unitholders. We also cannot predict the timing or final structure of any potential transaction or whether a combination will occur at all. TLLP has indicated that it is not interested in selling its interests in the Partnership. If the potential combination with TLLP does not occur, then our strategic options may be limited and, as a result, our business prospects may be negatively affected.

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 QEPFSC. For more information regarding the litigation with QGC, refer to Note 10 - Commitments and Contingencies, in Item 8 of Part II, and Legal Proceedings in Item 3, Part I of this Annual Report on Form 10-K.

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

Our Contracts Subject Us to Renewal Risks. We gather and transport crude oil and natural gas, process and treat natural gas and fractionate and transport the volumes of NGL on our assets under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio.

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

If a customer’s actual throughput volumes or volumes processed are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract year or the term of the minimum volume commitment, as applicable. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering or processing fee. To the extent that a customer’s actual throughput volumes or volumes processed are above or below its minimum volume commitment for the applicable period, several of our gathering and processing agreements with minimum volume commitments contain provisions that allow the customer to use the excess volumes or the shortfall payment as 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 or volumes processed 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 volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, we would not receive gathering or processing fees on volumes in excess of a customer’s applicable minimum volume commitment (depending on the terms of the specific gathering or processing 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 or volumes processed exceed its minimum volume commitment in the applicable period, it is entitled to apply the excess volumes 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 or volumes processed 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 or processing 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.

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

Certain of Our Assets Have Been in Service for Several Decades. There Could Be Increased Maintenance or Repair Expenses and Downtime Associated with Our Assets that Could Have an Adverse Effect on Our Business, Operating Results and Financial Condition. Certain of our gathering systems and processing plants have been in service for several decades. The age and condition of our pipeline systems and processing plants could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our assets could have an adverse effect on our business, results of operations and financial condition.

Our Business Involves Many Hazards and Operational Risks, Some of Which May Not Be Fully Covered By Insurance. If a Significant Accident or Event Occurs for Which We Are Not Adequately Insured, or If We Fail to Recover All Anticipated Insurance Proceeds for Significant Accidents or Events for Which We Are Insured, Our Operations and Financial Results Could Be Adversely Affected. Our operations are subject to all of the risks and hazards inherent in the gathering and transportation of crude oil and natural gas, the processing and treating of natural gas, and the fractionation and transportation of NGL, 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, natural gas, or NGL 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 facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners or operators of our assets, pursuant to any indemnification rights, for potential environmental liabilities.

Terrorist or Cyber-attacks and Threats, Escalation of Military Activity in Response to these Attacks or Acts of War Could Have a Material Adverse Effect on Our Business, Financial Condition or Results of Operations. Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. 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 Consider Strategic Acquisition Opportunities. If We Are Unable to Make Acquisitions on Economically Acceptable Terms, 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. 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, 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.

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.

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.

The Credit and Risk Profile of Our General Partner and Its Owner, TLLP, 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 TLLP may be factors considered in credit evaluations of us. This is because our General Partner, which is owned by TLLP, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in the financial condition of TLLP, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness, or a downgrade of TLLP’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 TLLP, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of TLLP 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.

As of December 31, 2014, we had $210.0 million outstanding and a borrowing capacity of $500.0 million under our Affiliate Credit Agreement. 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 and transportation of crude oil and natural gas, the processing and treating of natural gas and the fractionation and transportation of NGL 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 Affiliate Credit Agreement Could Adversely Affect Our Business, Financial Condition, Results of Operations, Ability to Make Distributions to Unitholders and Value of Our Common Units. The Affiliate Credit Agreement is likely to limit our ability to, among other things:


•	incur or guarantee additional debt;


•	make distributions on or redeem or repurchase units;


•	make certain investments and acquisitions;


•	make capital expenditures;


•	incur certain liens or permit them to exist;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

The provisions of the Affiliate Credit Agreement 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 Affiliate Credit Agreement 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, Plants and Related Facilities Are Located, Which Could Result in Disruptions to Our Operations. We do not own all of the land on which our pipelines, plants and related facilities are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. 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 Facilities Are Located On Native American Tribal Lands and Are Subject to Various Federal and Tribal Approvals and Regulations, Which May Increase Our Costs and Delay or Prevent Our Efforts to Conduct Planned Operations. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affair 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 majority of our customers’ oil and natural gas production is developed from unconventional sources, such as shales and tight sandstones, 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.

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 gathering systems and processing, treating and fractionation facilities and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. 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 gathering systems and processing, treating and fractionation facilities, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

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

The Majority of Our Pipelines Are Not Subject to Regulation By the FERC; However, a Change in the Jurisdictional Characterization of Our Assets, or a Change in Policy, Could Result in Increased Regulation of Our Assets Which Could Materially and Adversely Affect Our Financial Condition, Results of Operations and Cash Flows. A substantial majority of our assets 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 all of the facilities we consider to be gathering facilities, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by the FERC on a case-by-case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act (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 and Processing, Treating and Fractionation Facilities Are Subject to State Regulation That Could Materially and Adversely Affect Our Operations and Cash Flows. State regulation of gathering facilities and processing, treating and fractionation facilities includes safety and environmental requirements. In addition, several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations 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 gathering, transportation, processing, treating and fractionation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:


•	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;


•	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;


•	the Clean Water Act and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;


•	the OPA and analogous state laws that establish strict liability for releases of oil into waters of the United States;


•	the RCRA and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;


•	the ESA that restricts activities that may affect endangered and threatened species or their habitats; and


•	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 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. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. Several of the EPA’s GHG rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of 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 (the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act requires the Commodity Futures Trading Commission (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 January 22, 2015. 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.

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.

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 TLLP and Tesoro, 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 TLLP’s Business Decisions and Operations, and neither TLLP nor any of its affiliates, including Tesoro, is Under Any Obligation to Adopt a Business Strategy That Favors Us. TLLP owns a 2.0% general partner interest and a 55.8% limited partner interest in us and owns and controls our General Partner. Additionally, Tesoro owns an approximate 2.0% general partner interest in TLLP and owns and controls its 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, TLLP. Conflicts of interest may arise between TLLP and its affiliates, including our General Partner and Tesoro, 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 TLLP and Tesoro, over the interests of our common unitholders. These conflicts include, among others, the following situations:

•

neither our Partnership Agreement nor any other agreement requires TLLP or its affiliates, including Tesoro, to pursue a business strategy that favors us, and TLLP may choose to make these decisions in the best interests of TLLP and its partners and affiliates, including Tesoro. TLLP and its affiliates, including Tesoro, may choose to shift the focus of their respective investment and growth to areas not served by our assets;


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


•	our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;


•	except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;


•	our General Partner 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;

•

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;


•	our General Partner determines which costs incurred by it are reimbursable by us;


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

•

our Partnership Agreement permits us to classify up to $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;


•	our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;


•	our General Partner intends to limit its liability regarding our contractual and other obligations;


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


•	our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates;


•	our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and

•

our General Partner may 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 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 growth 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 growth 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 Affiliate Credit Agreement 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 TLLP and its affiliates) after the subordination period has ended. As of December 31, 2014, TLLP owns 13.8% of the outstanding common units and all of our outstanding subordinated units. See Part II, Item 5 Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities for a discussion of the timing for the termination of the subordination period.

Our Partnership Agreement Restricts the Remedies Available to Holders of Our Common and Subordinated Units for Actions Taken By Our General Partner That Might Otherwise Constitute Breaches of Fiduciary Duty. Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:

•

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


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

•

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 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 Amended Omnibus Agreement, our General Partner determines the amount of these expenses. Under the terms of the Amended Omnibus Agreement we will be required to reimburse TLGP, TLLP and its affiliates for the provision of certain general and administrative services to us. Our General Partner and its affiliates also may provide us other services for which we will be charged fees as determined by our General Partner. Payments to our General Partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders.

Unitholders Have Very Limited Voting Rights and, Even If They Are Dissatisfied, They Cannot Remove Our General Partner Without Its Consent. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner or the Board of our General Partner and will have no right to elect our General Partner or the Board of our General Partner on an annual or other continuing basis. The Board of our General Partner is chosen by the members of our General Partner, which are wholly-owned subsidiaries of TLLP, which is itself controlled by Tesoro. 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, 2014, 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 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 TLLP to transfer its membership interest in our General Partner to a third party. The new partners of our General Partner would then be in a position to replace the Board and officers of our General Partner with their own choices and to control the decisions taken by the Board 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 TLLP selling or contributing additional midstream assets to us, as TLLP 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 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 Affiliate Credit Agreement prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


•	our unitholders’ proportionate ownership interest in us will decrease;


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


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


•	the ratio of taxable income to distributions may decrease;


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


•	the market price of our common units may decline.

TLLP 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. TLLP 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 TLLP 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 TLLP and Tesoro, 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 Amended Omnibus Agreement will prohibit TLLP or any other affiliates of our General Partner, including Tesoro, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, TLLP and other affiliates of our General Partner, including Tesoro may acquire, construct or dispose of additional midstream assets, including midstream assets owned by QEPFS, in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from TLLP, Tesoro 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, 2014, our General Partner and its affiliates own approximately 13.8% of our common units. At the end of the subordination period, 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:


•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or


•	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 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 will 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 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 $2.0 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 (the “IRS”) Were to Treat Us as a Corporation for Federal Income Tax Purposes, Which Would Subject Us to Entity-Level Taxation, Then Our Cash Available for Distribution to Our Unitholders Would Be Substantially Reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

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

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEPFSC’s former affiliate, QGC and its affiliate Wexpro, filed a complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the “1993 Agreement”) executed when the parties were affiliates. TLLP has agreed to indemnify QEPFSC for this claim under the acquisition agreement for QEPFS. Under the 1993 Agreement, certain of QEPFSC’s systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service calculation. The 1993 Agreement was assigned to QEPFS on December 2, 2014 in connection with the Acquisition. QGC is disputing the annual calculation of the gathering rate, which has been calculated in the same manner since 1998, without objection by QGC. At the closing of the IPO, the assets and agreement discussed above was assigned to QEP Midstream. QGC amended its complaint to add QEP Midstream as a defendant in the litigation. Prior to the Acquisition, QEP Midstream was indemnified by QEPFSC and, effective December 2, 2014, by Tesoro Logistics for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the QEP Midstream Omnibus Agreement and the Amended Omnibus Agreement, respectively. QGC has netted the disputed amounts from its monthly payments of the gathering fees to QEPFSC and has continued to net such amounts from its monthly payment to QEP Midstream. The total netted from its monthly payments to date were $14.1 million through December 31, 2014. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits.

We had previously recorded the amounts QGC netted from its monthly payments as deferred revenue with a related receivable. As a result of the partial summary judgment, we reversed the deferred revenue and related third party receivables. In connection with the indemnification of such losses under the Amended Omnibus Agreement, we received a non-cash contribution of $6.5 million during the year ended December 31, 2014 related to the pre-IPO amounts and have a receivable and related contribution for the remaining amount net within equity. There was no impact of the partial summary judgment or indemnification on our consolidated statement of income for the year ended December 2014. As any additional losses have been indemnified, we believe the outcome of this matter will not have a material impact on our liquidity, financial position, or results of operations.

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.

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 initial public offering (“IPO”), the operations comprising the Partnership were owned by QEP Resources Inc. 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 for 2014 and 2013.



	Unit Price Range
	High Price		Low Price		Distribution Per Common Unit
	(per unit)
2014
First quarter	$	25.67	$	21.31	$	0.27
Second quarter	25.92		22.10		0.28
Third quarter	27.16		23.19		0.30
Fourth quarter	23.70		14.42		0.31
Total					$	1.16
2013
Third quarter⁽¹⁾	$	22.71	$	21.73	$	0.13
Fourth quarter	23.83		21.84		0.26
Total					$	0.39

____________


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

As of March 2, 2015, three registered holders own 23,039,580, or 86%, of our outstanding common units, including 23,038,280 common units held in street name. In addition, as of March 2, 2015, Tesoro Logistics LP and its affiliates held 3,701,750 of our common units.

The Partnership has also issued 26,705,000 subordinated units and 1,090,495 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 QEP Midstream Partners GP, LLC (our “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.

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 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 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; 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 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.

Early Termination of the Subordination Period. Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2014, that each of the following tests are met:


•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $1.50 (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

•

the adjusted operating surplus generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.50 (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partners units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and


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

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 Affiliate Credit Agreement that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Our General Partner is currently entitled to 2.0% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 1,090,495 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
	Total Quarterly Distribution Per Unit Target Amount		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	%

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 2014. Neither the Partnership nor any affiliated purchaser purchased equity securities of the Partnership during the fourth quarter of 2014.

ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for the four years ended December 31, 2014, 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 four 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
	Year Ended December 31, 2014			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			Successor			Predecessor			Predecessor			Predecessor
	(in millions, except per unit information)
Results of Operations
Revenues	$	123.2		$	48.1		$	100.3		$	162.2		$	155.9
Operating income	46.9			20.3			40.2			72.4			71.8
Net income attributable to QEP Midstream or Predecessor	50.0			19.1			38.9			67.3			60.3
Net income attributable to QEP Midstream per limited partner unit (basic and diluted):
Common units	$	0.91		$	0.35
Subordinated units	$	0.91		$	0.35
Distributions per unit	$	1.16		$	0.39
Weighted-average limited partner units outstanding (basic and diluted):
Common units	26.7			26.7
Subordinated units	26.7			26.7
Financial Position (at period end)
Total Assets	$	648.9		$	579.9		$	685.6		$	725.4		$	714.3
Capitalization
Long-term debt	210.0			—			64.6			131.1			174.6
Total equity	399.2			527.6			577.4			552.3			502.4
Cash Flow Provided by (Used in) Continuing Operations
Net cash provided by operating activities	$	100.3		$	31.6		$	90.9		$	107.0		$	97.5
Capital expenditures	(18.3		)	(14.2		)	(9.1		)	(43.7		)	(28.6		)
Net cash used in investing activities	(124.9		)	(13.7		)	(8.5		)	(43.4		)	(28.5		)
Net cash provided by (used in) financing activities	20.9			—			(82.7		)	(64.7		)	(68.0		)
Non-GAAP Measures
Adjusted EBITDA⁽¹⁾	$	88.7		$	31.5		$	66.7		$	115.1		$	111.8
Distributable Cash Flow⁽¹⁾	$	72.4		$	27.5

____________


⁽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.

Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)



				Year Ended
				December 31, 2013
	Year Ended December 31, 2014			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			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	$	50.0		$	19.1		$	38.9		$	67.3		$	60.3
Interest expense, net of other income	4.0			0.9			2.6			8.6			12.7
Depreciation and amortization	32.0			11.7			25.0			39.8			38.3
Noncontrolling interest share of depreciation and amortization⁽¹⁾	(2.6		)	(1.0		)	(1.6		)	(2.8		)	(2.7		)
Deferred revenue associated with minimum volume commitments	—			—			—			—			1.0
QEP Midstream share of unconsolidated affiliate's depreciation and amortization⁽²⁾	2.9			0.8			1.3			2.2			2.2
Loss from early extinguishment of debt	2.4			—			—			—			—
Net loss from asset sales	—			—			0.5			—			—
Adjusted EBITDA	$	88.7		$	31.5		$	66.7		$	115.1		$	111.8
Cash interest paid	(3.4		)	(0.7		)
Maintenance capital expenditures	(13.0		)	(13.1		)
Reimbursements for maintenance capital expenditures	1.0			9.6
Cash adjustments for non-controlling interest and equity method investments	(1.2		)	—
Non-cash long-term compensation expense	0.3			0.2
Distributable Cash Flow	$	72.4		$	27.5

See page 52 for footnotes to this table.



				Year Ended
				December 31, 2013
	Year Ended December 31, 2014			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			Successor			Predecessor			Predecessor			Predecessor
	(in millions)
Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flows
Net cash provided by operating activities	$	100.3		$	31.6		$	90.9		$	107.0		$	97.5
Noncontrolling interest share of depreciation and amortization⁽¹⁾	(2.6		)	(1.0		)	(1.6		)	(2.8		)	(2.7		)
QEP Midstream share of unconsolidated affiliate's depreciation and amortization ⁽²⁾	2.9			0.8			1.3			2.2			2.2
Loss (Income) from unconsolidated affiliates, net of distributions from unconsolidated affiliates	1.0			(0.1		)	(1.1		)	(0.6		)	(3.3		)
Net income attributable to noncontrolling interest	(3.7		)	(1.5		)	(2.5		)	(3.7		)	(3.2		)
Interest expense	4.0			0.9			2.6			8.6			12.7
Deferred revenue associated with minimum volume commitment payments⁽³⁾	—			—			—			—			1.0
Working capital changes	(12.0		)	1.4			(22.9		)	4.4			7.6
Amortization of deferred financing charges	(0.6		)	(0.2		)	—			—			—
Equity-based compensation expense	(0.6		)	(0.4		)	—			—			—
Adjusted EBITDA	$	88.7		$	31.5		$	66.7		$	115.1		$	111.8
Cash interest paid	(3.4		)	(0.7		)
Maintenance capital expenditures	(13.0		)	(13.1		)
Reimbursements for maintenance capital expenditures	1.0			9.6
Cash adjustments for non-controlling interest and equity method investments	(1.2		)	—
Non-cash long-term compensation expense	0.3			0.2
Distributable Cash Flow	$	72.4		$	27.5

____________


⁽¹⁾	Represents the noncontrolling interest’s 22% share of depreciation and amortization attributable to Rendezvous Gas Services L.L.C. (“Rendezvous Gas”).

⁽²⁾

Represents QEP Midstream’s share of Three Rivers Gathering, L.L.C. (“Three Rivers Gathering”) and Green River Processing, LLC (“Green River Processing”) depreciation and amortization. For the year ended December 31, 2014, $1.4 million was attributable to Three Rivers Gathering and $1.5 million was attributable to Green River Processing. For the period from August 14, 2013, through December 31, 2013, for the period from January 1, 2013, through August 13, 2013, and for the years ended December 31, 2012 and December 31, 2011, all unconsolidated affiliate depreciation and amortization is related to Three Rivers Gathering.

⁽³⁾

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 U.S.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.

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 for 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 in reference to periods 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 Resources” refers to QEP Resources, Inc. and its consolidated subsidiaries. Additionally, “TLLP” refers to Tesoro Logistics LP 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 is a master limited partnership formed to own, operate, acquire and develop midstream energy assets.

On August 14, 2013, the Partnership completed its IPO selling 23.0 million common units, including the exercise of the underwriters’ over-allotment. The Partnership received net proceeds of $449.6 million from the sale of the common units.

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing from QEP Field Services Company (“QEPFSC”) for $230.0 million (the “Green River Processing Acquisition”). The Green River Processing Acquisition was funded with $220.0 million of borrowings under the Partnership’s $500 million revolving credit facility (the “Prior Credit Facility”) and cash on hand.

On December 2, 2014, QEP Resources’ midstream business was acquired by TLLP, which included all of the issued and outstanding membership interest of QEP Field Services, LLC (“QEPFS”), a wholly-owned subsidiary of QEPFSC formed for purposes of consummating the QEP Field Services acquisition, pursuant to the Membership Interest Purchase Agreement, dated as of October 19, 2014, by and between TLLP and QEPFSC. QEPFS is the owner of QEP Midstream’s general partner, QEP Midstream Partners GP, LLC (our “General Partner”), which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights. The acquisition also included an approximate 56% limited partner interest in the Partnership (collectively, the “Acquisition”). Prior to the Acquisition, QEPFSC owned and operated QEP Midstream’s general partner. This resulted in a change of control of the Partnership’s general partner and the Partnership became a consolidated subsidiary of TLLP on the acquisition date. The transaction included consideration of $230 million paid by TLLP to QEP Resources, which was used to refinance the Partnership’s debt outstanding under the Prior Credit Facility. The transaction did not involve the sale or purchase of any QEP Midstream common units held by the public. Prior to this transaction, QEP Resources, through its wholly-owned subsidiary QEPFSC, served as the Partnership’s general partner and owned a 2% general partner interest, all of the Partnership’s incentive distribution rights and an approximate 56% limited partner interest in the Partnership.

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. Additionally, we have a 40% interest in two gas processing complexes through the Green River Processing Acquisition. 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 365 miles of natural gas gathering pipelines, 134 miles of crude oil gathering pipelines, 25 miles of water gathering pipelines and a 60-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have total natural gas throughput capacity of 737 MMcf/d, total crude oil and condensate throughput capacity of 7,137 barrels per day (“bpd”), total water throughput capacity of 21,990 bpd, and a total of 40,800 bpd throughput capacity on our FERC-regulated pipeline.

◦

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 QEPFS 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 Company LLC’s (“Rendezvous Pipeline”) sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEPFS’ Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 450 MMcf/d.

◦

Green River Processing. Green River Processing owns the Blacks Fork Processing Complex and the Emigrant Trail Processing Plant, both of which are located in southwest Wyoming. The aggregate processing capacity of Green River Processing is 890 MMcf per day, comprised of 560 MMcf per day of cryogenic processing capacity and 330 MMcf per day of Joule-Thomson processing capacity. In addition, there is 15,000 bpd of natural gas liquids (“NGL”) fractionation capacity at the Blacks Fork Processing Complex.


•	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 504 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.

•

Three Rivers Gathering System. Three Rivers Gathering, L.L.C. (“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, L.L.C. (“Uintah Basin Field Services”), an equity method investment in which QEPFS owns a 38% interest, and other third-party volumes to gas processing facilities owned by QEPFS 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 natural gas and crude oil gathering system located in the Williston Basin in McLean County, North Dakota. The Williston Gathering System includes 20 miles of gas gathering pipelines, 18 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 bpd 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 QEPFS owns in the Uinta Basin Gathering System (collectively referred to as the “Uinta Basin Gathering System”). These assets were retained by QEPFS 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. We have provided supplemental 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 the region where we operate, several producers have announced lower drilling expenditures for 2015. Our 2015 capital plan primarily includes compression projects which we expect will generate incremental volumes independent of drilling plans.

On January 23, 2015, the Partnership declared its quarterly cash distribution totaling $17.1 million or $0.31 per unit, for the fourth quarter of 2014. This distribution was paid on February 13, 2015, to unitholders of record on the close of business on February 3, 2015.

Our Operations

Our results are driven primarily by the volumes of natural gas and crude oil we gather and the fees charged for such services. We connect wells to gathering lines through which crude oil may be delivered to a downstream pipeline and ultimately to end-users, and 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 natural gas and crude oil 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 natural gas and crude oil 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. Approximately 4% of our Partnership’s revenue was generated through the sale of condensate volumes that we collect on our gathering systems during the year ended December 31, 2014. Although the Partnership has entered into a fixed price condensate sales agreement with QEPFS, 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 “Commodity Price Risk” in Quantitative and Qualitative Disclosures about Market Risk in Item 7A for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

With the Green River Processing Acquisition, our activities have expanded to include the processing of natural gas to separate NGL from the natural gas, fractionating the resulting NGL into the various components and selling or delivering pipeline quality natural gas and NGL to various industrial and energy markets as well as interstate pipeline systems. Our results from Green River Processing are primarily driven by commodity prices for NGL and natural gas, as well as the volumes of natural gas we process under fee-based agreements. Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into the Keep-Whole Commodity Fee Agreement (the “Keep-Whole Commodity Agreement”) with Tesoro Refining & Marketing Company LLC, a wholly-owned subsidiary of Tesoro Corporation (“TRMC”), to minimize and mitigate commodity price risk. 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 this agreement.

We have significant acreage dedications from several of our largest customers. 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 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 throughput volumes, gathering expenses, maintenance and growth capital expenditures, Adjusted EBITDA and Distributable Cash Flow. Both Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “Item 6. Selected Financial Data” for definitions of these 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 natural gas, crude oil and NGL, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in natural gas, crude 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 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 Growth 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 growth 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 capital 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 growth capital expenditures and attempt to negotiate terms in our 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 and 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.

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 other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;


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


•	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 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. 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 exclude 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 natural gas and crude oil production 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.We anticipate the current level of exploration and production activities in all of the areas in which we operate to fluctuate, although we have no control over this activity. Fluctuations in natural gas and crude oil prices could affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas and crude oil reserves.

Rising operating costs and inflation

During most of 2014, the level of exploration, development and production activities across the United States resulted in increased competition for personnel and equipment. This caused increases in the prices we paid 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.

Commodity price risk

Future exposure to changes in natural gas and NGL prices could have a material adverse effect on our business, results of operations and financial condition as changes in prices will impact our production levels and gathering volumes. On December 2, 2014, following the completion of the Acquisition, Green River Processing entered into the Keep-Whole Commodity Agreement with TRMC, to minimize and mitigate commodity price risk. 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 this agreement.

Impact of Interest Rates

Interest rates have been relatively low in recent years. If interest rates rise, our 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 units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets and may limit our ability to expand our operations or make future acquisitions.

Regulatory compliance

The regulation of natural gas and crude oil transportation activities by the FERC, and other federal and state regulatory agencies, including the Department Of Transportation (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 natural gas and crude oil. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of natural gas and crude oil producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of natural gas and crude oil, and therefore throughput on our gathering systems.

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.

Investment in Green River Processing

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing from QEPFSC for $230.0 million. Green River Processing owns the Blacks Fork processing complex and the Emigrant Trail processing complex, both of which are located in southwest Wyoming. The Green River Processing Acquisition is accounted for as an equity method investment in an unconsolidated affiliate. For the year ended December 31, 2014, Green River Processing net income attributable to QEP Midstream was $10.2 million.

Assets not included in the Partnership

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

General and administrative expenses

General and administrative expenses were allocated to the Predecessor based on its proportionate share of QEP Resources’ gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable. The Predecessor’s general and administrative expenses included costs allocated by QEP Resources and related to various business and corporate services, and compensation-related costs. General and administrative expenses allocated to the Predecessor was $13.6 million for the period from January 1, 2013, through August 13, 2013.

In connection with the IPO, the Partnership entered into the Omnibus Agreement on August 14, 2013, (the “Original Omnibus Agreement”) with QEP Resources, which established the general and administrative expense charged to the Partnership. In accordance with the Original Omnibus Agreement, a combination of direct and allocated charges for administrative and operational services is charged to the Partnership. The annual fee was set to $13.8 million. For the period from August 14, 2013, through December 31, 2013, the Partnership was charged $4.6 million under the Original Omnibus Agreement. For the period from January 1, 2014, through December 1, 2014, the Partnership was charged $12.7 million under the Original Omnibus Agreement.

On December 2, 2014, and in connection with the Acquisition, the Partnership entered into the First Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”) with TLGP and affiliates. The Amended Omnibus Agreement restated and amended the Original Omnibus Agreement dated August 14, 2013, and established the general and administrative expense that TLGP would charge to the Partnership. TLGP charged the Partnership a combination of direct and allocated charges for administrative and operational services in accordance with the amended agreement. For the period from December 2, 2014, through December 31, 2014, the Partnership was charged $1.1 million under the Amended Omnibus Agreement by TLGP.

In addition to the charges under the Amended Omnibus Agreement, we incur incremental general and administrative expenses attributable to operating as a publicly traded partnership. 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 expenses will also include compensation expense associated with the Long-Term Incentive Plan (“LTIP”), which was implemented in connection with the IPO and expenses relating to events such as asset acquisitions. The Partnership incurred $4.0 million of incremental general and administrative expenses including $1.4 million of transaction costs related to the Green River Processing Acquisition for the year ended December 31, 2014.

Working capital

The impact of all affiliated transactions of the Predecessor historically was net settled within QEP Resources’ consolidated financial statements because these transactions related to QEP Resources and were funded by QEP Resources’ working capital. Third-party transactions were also funded by QEP Resources’ working capital. Since the IPO, all affiliate and third-party transactions, excluding acquisitions, have been funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

Interest expense

Prior to the IPO, we incurred interest expense on affiliate notes payable to QEP Resources that was allocated to us. These balances were repaid in full 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. We entered into the $500.0 million Prior Credit Facility in connection with the IPO, which contained customary short-term interest rates and a commitment fee on the unused portion of the Prior Credit Facility. In connection with the Acquisition, the Partnership terminated the Prior Credit Facility and entered into a $500.0 million unsecured affiliate credit agreement with QEPFS dated December 2, 2014 (the “Affiliate Credit Agreement”), which contains customary short-term interest rates.

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). Our cash distribution policy is to 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 on internally generated cash flows and borrowings under our Affiliate Credit Agreement to satisfy our capital expenditure requirements.

Results of Operations

The discussion of our historical performance and financial condition is presented for the Partnership (Successor), for the year ended December 31, 2014, and the period from August 14, 2013 through December 31, 2013, and for the Predecessor for the period from January 1, 2013, through August 13, 2013, and the year ended December 31, 2012.

As previously discussed, the historical financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes 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, adjusted for transactions that occurred as a result of 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. Therefore, we have also included the results of operations for the year ended December 31, 2013, on a pro forma basis.

The supplemental pro forma financial data is for informational purposes only and was derived from the Predecessor financial information adjusted to give effect to events and circumstances that are directly attributed to the IPO transaction as if it had occurred on January 1, 2013, that are factually supportable and, with respect to the Consolidated Statements of Income, are expected to have a continuing impact on the consolidated results. These adjustments include removing the results of the assets retained by the Predecessor consisting of the Uinta Basin Gathering System and general support equipment, adjusting general and administrative expense to eliminate general and administrative expense allocated to the Predecessor and to include the estimated incremental expenses that would have occurred as a result of operating as a public company and the execution of the Original Omnibus Agreement concurrent with the IPO, and adjusting interest expense to eliminate the related party debt that was settled in conjunction with the IPO and to estimate interest expense related to the Prior Credit Facility entered into in connection with the IPO. The unaudited pro forma information should not be relied upon as necessarily being indicative of the results that may be obtained in the future.

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.



				Year Ended
				December 31, 2013
	Year Ended December 31, 2014			Period From August 14, 2013, through December 31, 2013			Period From January 1, 2013, through August 13, 2013										Year Ended December 31, 2012
	Successor			Successor			Predecessor as reported			Pro Forma Adjustments⁽¹⁾			Pro Forma				Predecessor
	(in millions, except per unit information)
Revenues
Gathering and transportation	$	117.9		$	46.1		$	92.9		$	(20.0	)	$	119.0			$	151.3
Condensate sales	5.3			2.0			7.4			(1.8		)	7.6				10.9
Total revenues	123.2			48.1			100.3			(21.8		)	126.6				162.2
Operating expenses
Gathering expenses	24.5			9.8			19.7			(5.5		)	24.0				29.9
General and administrative	17.8			5.5			13.6			(2.9		)	16.2			⁽²⁾	17.0
Taxes other than income taxes	2.0			0.8			1.3			(0.5		)	1.6				3.1
Depreciation and amortization	32.0			11.7			25.0			(5.7		)	31.0				39.8
Total operating expenses	76.3			27.8			59.6			(14.6		)	72.8				89.8
Net loss from property sales	—			—			(0.5		)	0.4			(0.1		)		—
Operating income	46.9			20.3			40.2			(6.8		)	53.7				72.4
Other income	—			—			—			—							0.1
Income from unconsolidated affiliates	13.2			1.2			3.8			(2.2		)	2.8				7.2
Loss from early extinguishment of debt	(2.4		)	—			—			—			—				—
Interest expense	(4.0		)	(0.9		)	(2.6		)	1.9			(1.6		)	⁽³⁾	(8.7		)
Net income	53.7			20.6			41.4			(7.1		)	54.9				71.0
Net income attributable to noncontrolling interest	(3.7		)	(1.5		)	(2.5		)	—			(4.0		)		(3.7		)
Net income attributable to QEP Midstream or Predecessor	$	50.0		$	19.1		$	38.9		$	(7.1	)	$	50.9			$	67.3
Operating Statistics
Natural gas throughput in millions of MMBtu
Gathering and transportation	294.7			115.0			230.9			(45.7		)	300.2				387.8
Equity interest⁽⁴⁾	21.3			7.1			13.4			(1.0		)	19.5				27.5
Total natural gas throughput	316.0			122.1			244.3			(46.7		)	319.7				415.3
Throughput attributable to noncontrolling interests⁽⁵⁾	(11.2		)	(3.6		)	(6.7		)	—			(10.3		)		(12.1		)
Total throughput attributable to QEP Midstream or Predecessor	304.8			118.5			237.6			(46.7		)	309.4				403.2
Crude oil and condensate gathering system throughput volumes (MBbls)	4,481.4			1,743.2			3,243.1			—			4,986.3				5,297.4
Water gathering volumes (MBbls)	4,996.0			1,765.3			2,450.3			—			4,215.6				3,998.4
Condensate sales volumes (MBbls)	62.4			23.4			90.6			(21.8		)	92.2				125.8
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.32		$	0.34		$	0.35					$	0.33			$	0.34
Average oil and condensate gathering fee (per barrel)	$	2.32		$	2.13		$	2.44					$	2.49			$	2.31
Average water gathering fee (per barrel)	$	1.87		$	1.85		$	1.82					$	1.83			$	1.84
Average condensate sale price (per barrel)	$	85.25		$	85.25		$	81.63					$	82.67			$	86.06
Non-GAAP Measures
Adjusted EBITDA⁽⁶⁾	$	88.7		$	31.5		$	66.7		$	(15.3	)	$	82.9			$	115.1
Distributable Cash Flow⁽⁶⁾	$	72.4		$	27.5

____________


⁽¹⁾	Pro forma adjustments reflect pre-IPO operating results related to assets retained by our Predecessor at the time of the IPO, except as otherwise noted.


⁽²⁾	The pro forma adjustment for general and administrative expense eliminates general and administrative expense allocated to the Predecessor and includes the estimated incremental expenses that would have occurred as a result of operating as a public company and the execution of the Original Omnibus Agreement concurrent with the IPO.


⁽³⁾	The pro forma adjustment for interest expense eliminates historical interest expense due to QEP Resources as the related party debt was settled concurrent with the IPO, and includes the estimated interest expense related to the Prior Credit Facility, which includes amortization of deferred finance cost and commitment fees on the unused portion of the Prior Credit Facility.


⁽⁴⁾	For Successor periods, includes our 50% share of gross volumes from Three Rivers Gathering. For Predecessor periods, includes our 50% share of gross volumes from Three Rivers Gathering and our Predecessor’s 38% share of gross volumes from Uintah Basin Field Services.


⁽⁵⁾	Includes the 22% noncontrolling interest in Rendezvous Gas.


⁽⁶⁾	Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “Item 6. Selected Financial Data” above for definitions of these non-GAAP financial measures and reconciliations to the most directly comparable GAAP financial measures.

Successor Results of Operations

On August 14, 2013, the Partnership completed its IPO. Prior to the closing of the IPO, QEPFSC and the General Partner contributed, as capital contributions, $407.8 million of net assets representing their limited liability company interest in QEP Midstream Partners Operating, LLC (the “Operating Company”). The contribution of QEPFSC’s 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, two FERC-regulated pipelines and exclude the Uinta Basin Gathering System, which was retained by QEPFSC. Additionally, we have a 40% interest in two gas processing complexes through the Green River Processing Acquisition. The Partnership’s (Successor’s) operating results for the year ended December 31, 2014 and the period from August 14, 2013, through December 31, 2013, are presented below.

Year Ended December 31, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $117.9 million for the year ended December 31, 2014.

Natural gas gathering and transportation revenue was $94.9 million for the year ended December 31, 2014, with throughput of 304.8 million MMBtu and an average gas gathering and transportation fee of $0.32 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 202.9 million MMBtu of throughput, and our Vermillion Gathering System, which contributed 40.4 million MMBtu.

Crude oil and condensate gathering revenue was $10.4 million for the year ended December 31, 2014. The average gathering fee was $2.32 per barrel and throughput was 4,481.4 MBbls, of which 3,492.8 MBbls were attributable to our Green River Gathering System and 988.6 MBbls were attributable to our Williston Gathering System.

Water gathering revenue was $9.5 million for the year ended December 31, 2014, with throughput 4,996.0 MBbls and an average fee of $1.87 per barrel at our Green River Gathering System.

The remaining portion of gathering and transportation revenue for the year ended December 31, 2014, related to deficiency revenue of $3.1 million, $2.8 million of which was attributable to our Williston Gathering System and the remaining was attributable to our Vermillion Gathering System.

Condensate sales. Revenue from condensate sales was $5.3 million for the year ended December 31, 2014 from sales volumes of 62.4 Mbbls at an average price of $85.25 per barrel as a result of our fixed price sales agreement with QEP Resources, which was effective August 14, 2013.

Operating Expenses

Gathering expenses. Gathering expenses were $24.5 million for the year ended December 31, 2014, 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 $17.8 million for the year ended December 31, 2014, consisting of $12.7 million from charges under the Original Omnibus Agreement with QEP Resources, and $1.1 million from charges under the Amended Omnibus Agreement with TLGP. We also incurred $1.4 million of professional services fees related to the Green River Processing Acquisition, $0.6 million for equity-based compensation expense and other expenses related to operating as a publicly traded partnership.

Taxes other than income taxes. Taxes other than income taxes were $2.0 million for the year ended December 31, 2014, primarily attributable to property taxes on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $32.0 million for the year ended December 31, 2014, 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 $13.2 million for the year ended December 31, 2014, of which, $10.3 million of income related to our 40% interest in Green River Processing, acquired July 1, 2014, and $2.9 million of income related to our 50% interest in Three Rivers Gathering.

Interest expense. Interest expense was $4.0 million for the year ended December 31, 2014, consisting of $2.4 million related to interest expense on borrowings under the Prior Credit Facility and the Affiliate Credit Agreement on terms substantially similar to the Prior Credit Facility, $1.0 million in commitment fees and $0.6 million related to the amortization of debt issuance costs.

Period from August 14, 2013, through December 31, 2013 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $46.1 million for the period from August 14, 2013, through December 31, 2013 (the “2013 Successor Period”).

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 Resources’ 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 2013 Successor Period, 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 2013 Successor Period, 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 2013 Successor Period, from sales volumes of 23.4 Mbbls at an average price of $85.25 per barrel as a result of our fixed price sales agreement with QEP Resources, which was effective on August 14, 2013.

Operating Expenses

Gathering expenses. Gathering expenses were $9.8 million for the 2013 Successor Period, 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 2013 Successor Period, consisting of $4.6 million from charges under the Original 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 2013 Successor Period, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $11.7 million for the 2013 Successor Period.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $1.2 million for the 2013 Successor Period related to income related to our 50% interest in Three Rivers Gathering.

Interest expense. Interest expense was $0.9 million for the 2013 Successor Period, related to commitment fees paid on the unused portion of the Prior Credit Facility. There were no borrowings under the Prior Credit Facility during the 2013 Successor Period.

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 QEPFSC and was not part of the assets conveyed to the Partnership.

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 (the “2013 Predecessor Period”).

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 Resources’ Pinedale operations. Additional volumes related to 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 also contributed to our revenue.

Crude oil and condensate gathering revenue was $7.9 million for the 2013 Predecessor Period, 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 2013 Predecessor Period, 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 2013 Predecessor Period, from sales volumes of 90.6 Mbbls at an average 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 2013 Predecessor Period, 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 2013 Predecessor Period, from the allocation of costs by QEP Resources 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 2013 Predecessor Period, 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 2013 Predecessor Period.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $3.8 million for the 2013 Predecessor Period. 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 2013 Predecessor Period, related to interest charged on the Predecessor’s outstanding long-term debt with QEP Resources throughout the period.

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, the Predecessor’s Uinta Basin Gathering System, and our Vermillion Gathering System which contributed 201.7 million MMBtu, 78.6 million MMBtu and 52.0 million MMBtu of throughput, respectively.

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 barrel 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 was $7.4 million for the year ended December 31, 2012, driven by throughput of 3,998.4 Mbbls and an average fee of $1.84 per barrel 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 an average price of $86.06 per barrel, 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 Resources 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 Resources throughout the period.

Supplemental Pro Forma Analysis

As previously discussed, the historical financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes 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 and that reflects transactions that occurred as a result of 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. Therefore, we have also included the results of operations for the year ended December 31, 2014, on a pro forma basis.

Year Ended December 31, 2014, compared to Year Ended December 31, 2013 - Pro Forma

Revenue

Gathering and transportation. Gathering and transportation revenues decreased $1.1 million during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013.

Natural gas gathering and transportation revenues decreased $3.9 million during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, as a result of a lower gas gathering throughput of 4.6 million MMBtu and a 3% lower average gas gathering fee. The decrease in throughput is primarily due to a 5.8 million MMBtu decrease at our Vermillion Gathering System due to reduced drilling activities in that area and a temporary downstream interstate pipeline shutdown during the third quarter of 2014, and a 3.7 million MMBtu decrease at our Green River Gathering System due to QEP Resources’ reduction in natural gas production in the Pinedale field.

Crude oil and condensate gathering revenue decreased $0.7 million during the during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to a 10% decrease in gathering volume and a 7% decrease in average gathering fees. The decrease in throughput was primarily due to a 0.4 MBbls decrease at our Green River Gathering System and a 0.1 MBbls decrease at our Williston Gathering System.

Water gathering revenue was $1.7 million, or 22%, higher for the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to a 19% increase in gathering volume and a 2% rate escalation at our Green River Gathering System.

Deficiency revenue increased $1.8 million for the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to a $1.5 million increase in deficiency revenue at our Williston Gathering System and a $0.3 million increase at our Vermillion Gathering System.

Condensate sales. Condensate sales decreased $2.3 million during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to a 32% decrease in sales volumes, partially offset by a 3% increase in average gathering fees as a result of our fixed-price sales agreement with QEPFS. The decrease in sales volumes is attributable to a 63% decrease in volumes at our Green River Gathering System, partially offset by a 2% increase at our Vermillion Gathering System. Condensate sales variability is due in part to the timing of condensate deliveries to our customers and seasonal variability, as warmer ground temperatures in late summer result in lower condensate recoveries.

Operating Expenses

Gathering expense. Gathering expense increased by $0.5 million, or 2%, during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to increased labor and maintenance costs at our Vermillion Gathering System, partially offset by decreased labor and maintenance costs at our Williston Gathering Systems.

General and administrative. General and administrative expenses for the year ended December 31, 2014, increased by $1.6 million, or 10%, compared to the pro forma year ended December 31, 2013, primarily due to professional service fees incurred for the Green River Processing Acquisition.

Taxes other than income taxes. Taxes other than income taxes increased by $0.4 million during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, due to increased property taxes at the Green River Gathering System and the Vermillion Gathering System.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased by $10.4 million during the year ended December 31, 2014, compared to the pro forma year ended December 31, 2013, primarily due to $10.3 million of income related to our 40% interest in Green River Processing, acquired July 1, 2014. The remaining increase is attributable to our 50% ownership in Three Rivers Gathering.

Interest expense. Interest expense during the year ended December 31, 2014, increased $2.4 million compared to the pro forma year ended December 31, 2013, due to borrowings under the Prior Credit Facility and the Affiliate Credit Agreement for the Green River Processing Acquisition which closed on July 1, 2014.

Liquidity and Capital Resources

Prior to the IPO, our sources of liquidity included cash generated from operations and funding from QEP Resources. We historically participated in QEP Resources’ centralized cash management program under which the net balance of our cash receipts and cash disbursements were settled with QEP Resources on a periodic basis.

We maintain our own bank accounts and sources of liquidity. 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 Affiliate Credit Agreement, 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. 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
	Year Ended December 31, 2014			Period from August 14, 2013, through December 31, 2013			Period from January 1, 2013, through August 13, 2013			Year Ended December 31, 2012
	Successor			Successor			Predecessor			Predecessor
	(in millions)
Net cash provided by (used in):
Operating activities	$	100.3		$	31.6		$	90.9		$	107.0
Investing activities	(124.9		)	(13.7		)	(8.5		)	(43.4		)
Financing activities	20.9			—			(82.7		)	(64.7		)

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
	Year Ended December 31, 2014		Period from August 14, 2013, through December 31, 2013			Period from January 1, 2013, through August 13, 2013		Year Ended December 31, 2012
	Successor		Successor			Predecessor		Predecessor
	(in millions)
Net income	$	53.7	$	20.6		$	41.4	$	71.0
Non-cash adjustments to net income	34.6		12.4			26.6		40.4
Changes in operating assets and liabilities	12.0		(1.4		)	22.9		(4.4		)
Net cash provided from operating activities	$	100.3	$	31.6		$	90.9	$	107.0

Investing Activities. Our Predecessor’s historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP Resources. 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
	Year Ended December 31, 2014		Period from August 14, 2013, through December 31, 2013			Period from January 1, 2013, through August 13, 2013		Year Ended December 31, 2012
	Successor		Successor			Predecessor		Predecessor
	(in millions)
Total accrual capital expenditures	$	14.1	$	18.5		$	7.5	$	42.4
Change in accruals and non-cash items	4.2		(4.3		)	1.6		1.3
Total cash capital expenditures	$	18.3	$	14.2		$	9.1	$	43.7

In addition to the capital expenditures noted above, the Partnership acquired 40% of the membership interests in Green River Processing for $230.0 million. The cash flow statement amount of $106.9 million of cash investing outflows is due to the transaction being accounted for as entities under common control. The Partnership also made contributions to Green River Processing of $2.5 million, of which $2.1 million was capital expenditures related to various system maintenance projects and $0.4 million was for an operating expense reserve. Additionally, the Partnership had distributions from equity investments in excess of cumulative earnings of $2.8 million from its investment in Three Rivers Gathering.

Financing Activities. During the year ended December 31, 2014, net cash from financing activities was $20.9 million. This consisted of $210.0 million of net borrowings under the Prior Credit Facility and the Affiliate Credit Agreement, $60.6 million in unitholder distributions paid in 2014, and $6.3 million in distributions to its noncontrolling interest in Rendezvous Gas. Additionally, the Partnership had a cash distribution of $123.1 million equal to the amount of the Green River Processing Acquisition purchase price in excess of the carrying value of assets acquired.

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 Resources for $351.1 million. Additionally, the Partnership received $9.6 million from QEP Resources under the indemnification provisions of the Original 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 in distributions to its noncontrolling interest in Rendezvous Gas.

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 Resources 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 Resources compared to $63.6 million in 2011. In addition, our Predecessor had distributions to QEP Resources of $14.5 million and to its noncontrolling interest in Rendezvous Gas of $6.6 million in 2012.

Capital Requirements

The natural gas and crude oil 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.

•

Growth capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long-term. Growth capital expenditures include the acquisition of assets from QEPFS 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. Growth capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of growth 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.

Capital expenditures totaled $14.1 million for the year ended December 31, 2014 which includes expansion capital of $1.1 million and maintenance capital of $13.0 million. Maintenance capital expenditures of $13.0 million included $10.1 million related to the Green River Gathering System, of which $3.3 million related to a compressor maintenance overhaul project, $4.5 million related to system maintenance and $2.3 million related to a condensate pipeline repair and replacement project. The Partnership was reimbursed by QEP Resources for $1.1 million of pipeline repair costs pursuant to an indemnification provision in the Original Omnibus Agreement. The remaining maintenance capital expenditures of $2.9 million primarily related to compressor maintenance on the Vermillion Gathering System. Expansion capital expenditures of $1.1 million related primarily to a compressor replacement project on the Vermillion Gathering System and reimbursable well connects on the Williston Gathering System.

Capital expenditures totaled $18.5 million for the Partnership during the period from August 14, 2013, through December 31, 2013, 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 Resources for these costs pursuant to an indemnification provision in the Original 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. Growth 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 $50.0 million to $55.0 million for the year ending December 31, 2015. This amount includes approximately $10.0 million of maintenance capital and approximately $40.0 million to $45.0 million of expansion capital. Maintenance capital spending includes line replacement and odorization in the Pinedale area. Growth capital spending includes reducing pipeline pressures in Pinedale Field by compressor modifications in order to allow gas to flow more freely from wells. Growth capital spending also includes adding additional compression and gathering lines at Vermillion and connecting more producers into our system in North Dakota. Capital spending for well-connects will be included in growth capital in 2015, but was included in maintenance capital spending for the years ended December 31, 2014, 2013 and 2012. 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 2015 capital expenditures with cash flow generated from operations and borrowings under our Affiliate Credit Agreement.

Distributions

For the year ended December 31, 2014, the partnership paid $60.6 million in distributions to unitholders. Further, on January 23, 2015, the Partnership declared its quarterly cash distribution totaling $17.1 million, or $0.31 per unit for the fourth quarter of 2014. The distribution was paid on February 13, 2015 to unitholders of record on the close of business on February 3, 2015. The distribution for the fourth quarter of 2014 included $0.2 million in distributions related to the General Partner’s incentive distribution rights.

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.

The Prior Credit Facility and the Affiliate Credit Agreement

In connection with the IPO, we entered into the Prior 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 Prior Credit Facility contained an accordion provision that allowed the amount of the facility to be increased to $750.0 million with the agreement of the lenders. The Prior Credit Facility was 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, were pledged as collateral under the Prior Credit Facility. In addition, the Prior Credit Facility contained restrictions and events of default customary for transactions of this nature. For the period from January 1, 2014, through December 1, 2014, the unused portion of the Prior Credit Facility was subject to a commitment fee ranging from 0.325% to 0.500% per annum.

The Partnership borrowed $230.0 million under the Prior Credit Facility during the year ended December 31, 2014, to fund the Green River Processing Acquisition. The weighted average interest rate on borrowings during the period was 1.94%. As part of the Acquisition of QEPFS by TLLP on December 2, 2014, the outstanding amount of $230.0 million was repaid and the Prior Credit Facility was terminated.

Concurrent with the termination of the Prior Credit Facility, we entered into the $500.0 million unsecured, Affiliate Credit Agreement with QEPFS, on terms substantially similar to those of the Prior Credit Facility. Under the Affiliate Credit Agreement, QEPFS agreed to provide revolving loans and advances to us up to a borrowing capacity of $500.0 million. The Affiliate Credit Agreement is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. The Affiliate Credit Agreement is likely to limit our ability to, among other things:


•	incur or guarantee additional debt;


•	make distributions on or redeem or repurchase units;


•	make certain investments and acquisitions;


•	make capital expenditures;


•	incur certain liens or permit them to exist;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

The Affiliate Credit Agreement 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. As of December 31, 2014, there was $210.0 million outstanding under the Affiliate Credit Agreement, and the Partnership was in compliance with the covenants under the Affiliate Credit Agreement. During the year ended December 31, 2014, we incurred interest on borrowings under both the Prior Credit Facility and the Affiliate Credit Agreement at a blended rate of 1.94%. The maturity date of the Affiliate Credit Agreement is August 14, 2018.

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 Resources and Questar Gas Company (“QGC”), who account for approximately 67% and 15% 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 Resources and QGC. Consequently, we are subject to the risk of non-payment or late payment by QEP Resources 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 QEPFSC and the Partnership since the second quarter of 2012. The Partnership has been indemnified by TLLP 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 Amended Omnibus Agreement. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. As a result of our indemnification by TLLP, the outcome of this litigation is not expected to have a material impact on our financial condition, results of operations, or liquidity. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits. For more information regarding the litigation with QGC, refer to Note 10 - Commitments and Contingencies, in Item 8 of Part II, 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 Resources, for our revenues. If QEP Resources becomes unable to perform under the terms of our gathering agreements 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, 2014:



	Payments Due by Year
	Total		2015		2016		2017		2018		2019		After 2019
	(in millions)
Long-term debt	$	210.0	$	—	$	—	$	—	$	210.0	$	—	$	—
Asset retirement obligations⁽¹⁾	14.2		—		—		—		—		—		14.2
Amended Omnibus Agreement⁽²⁾	69.0		13.8		13.8		13.8		13.8		13.8		—
Total	$	293.2	$	13.8	$	13.8	$	13.8	$	223.8	$	13.8	$	14.2

____________


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


⁽²⁾	Our Amended Omnibus Agreement remains in effect between the Partnership and TLGP until a change in control of the Partnership. As we are unable to estimate the termination of the contract, we have included the fees for each of the five years following December 31, 2014 for disclosure purposes.

Related Parties

Our General Partner is owned by QEPFS, which became a subsidiary of TLLP as of December 2, 2014. As of December 31, 2014, QEPFS 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 1,090,495 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEPFS and TLLP are considered to be related party transactions because our General Partner and its affiliates own more than 5% of our equity interests. Prior to the Acquisition, QEPFS was owned by QEP Resources.

In connection with the IPO, QEP Midstream entered into various agreements with QEPFSC, QEP Resources and our General Partner including the following: the Original Omnibus Agreement, the Partnership Agreement, gathering and transportation agreements, a fixed priced condensate purchase agreement, operating agreements and other service agreements. Other than described below, the agreements with QEPFSC and QEP Resources were assigned to QEPFS, TLLP and TLLP’s general partner. The terms of the assigned agreements remained substantially similar subsequent to the Acquisition. 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. For a summary of revenue and expenses recognized pursuant to these agreements, refer to Item 8, Note 4 to our consolidated financial statements.

Affiliate Credit Agreement

On December 2, 2014, in connection with the Acquisition, we entered into the Affiliate Credit Agreement. Under the Affiliate Credit Agreement, QEPFS agreed to provide revolving loans and advances to us up to a borrowing capacity of $500.0 million. In conjunction with the closing of the Acquisition, we borrowed $230.0 million under the Affiliate Credit Agreement and used the funds for the repayment and termination of the Prior Credit Facility. The maturity date of the Affiliate Credit Agreement is August 14, 2018.

Omnibus Agreement

In connection with the IPO, the Partnership entered into the Original Omnibus Agreement on August 14, 2013, which established the general and administrative expense that QEP Resources would charge to the Partnership. In accordance with the Original Omnibus Agreement, QEP Resources charged the Partnership a combination of direct and allocated charges for administrative and operational services. The annual fee was set to $13.8 million. For the period from August 14, 2013, through December 31, 2013, the Partnership was charged $4.6 million under the Original Omnibus Agreement by QEP Resources. For the period from January 1, 2014, through December 1, 2014, the Partnership was charged $12.7 million under the Original Omnibus Agreement by QEP Resources.

On December 2, 2014, and in connection with the Acquisition, the Partnership entered into the Amended Omnibus Agreement with TLGP and affiliates. The Amended Omnibus Agreement restated and amended the Original Omnibus Agreement dated August 14, 2013, and established the general and administrative expense that TLGP would charge to the Partnership. TLGP charged the Partnership a combination of direct and allocated charges for administrative and operational services in accordance with the amended agreement. For the period from December 2, 2014, through December 31, 2014, the Partnership was charged $1.1 million under the Amended Omnibus Agreement by TLGP.

Keep-Whole Commodity Fee Agreement

Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into the five-year Keep-Whole Commodity Agreement with TRMC to minimize commodity price risk. Under the Keep-Whole Commodity Agreement with TRMC, TRMC pays Green River Processing a fee to process NGLs related to keep-whole agreements and delivers replacement natural gas to the producers on behalf of Green River Processing. Green River Processing pays TRMC a marketing fee in exchange for assuming the commodity risk. Terms and pricing under this agreement are revised each year.

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.

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. For other significant policies not discussed in this section, refer to Note 2 - Summary of Significant Accounting Policies, 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 crude oil gathering pipelines, transmission pipelines and compressors and are stated at the lower of historical cost, less accumulated depreciation or fair value, if impaired. We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred, except substantial compression overhaul costs that are capitalized and depreciated. Depreciation of gathering equipment is charged to expense using the straight-line method.

Impairment of Long-lived Assets

We evaluate whether long-lived assets have been impaired and determine if the carrying amount of our 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 2014, 2013 or 2012.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are associated with the retirement of tangible long-lived assets and 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. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at our credit-adjusted, risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the AROs and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Revenue Recognition

We provide 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. The Partnership defers revenue it receives for certain deficiency payments where the third party has the ability to meet the minimum volume commitment in a subsequent period pursuant to the terms of the specific agreement. 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.

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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

The Partnership’s Affiliate Credit Agreement contains a variable interest rate that exposes us to volatility in interest rates. At December 31, 2014, the Partnership had $210.0 million outstanding under the Affiliate Credit Agreement. If interest rates had increased or decreased 10% over the year ended December 31, 2014, at our average level of borrowing for those same periods, our interest expense would have increased or decreased by $0.2 million for the year ended December 31, 2014.

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 slight discount to the price of crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of revenues generated under these arrangements compared to our overall revenues. Historically, we have not entered into commodity derivative instruments because of the minimal impact on our revenues; however, we have a fixed-price Condensate Purchase Agreement with QEPFS, which requires us to sell and QEPFS 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.

With our Green River Processing Acquisition, a portion of our profitability is directly affected by prevailing commodity prices related to keep-whole processing contracts. Our non-wholly owned subsidiary Green River Processing processes gas for certain producers under “keep-whole” processing agreements. Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a BTU content equivalent to the NGLs removed. The operating margin for these agreements are determined by the spread between NGL sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). Effective December 2, 2014, following the completion of the Acquisition, TRMC and Green River Processing entered into the Keep-Whole Commodity Agreement to minimize commodity price risk. Under the Keep-Whole Commodity Agreement with TRMC, TRMC pays Green River Processing a fee to process NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of Green River Processing. Green River Processing pays TRMC a marketing fee in exchange for assuming the commodity risk.

Terms and pricing under this agreement are revised each year. The Keep-Whole Commodity Agreement minimizes the impact of commodity price movement during the annual period subsequent to renegotiation of terms and pricing each year. However the annual fee we charge TRMC could be impacted as a result of any changes in the spread between NGL sales prices and the price of natural gas. 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 this agreement.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Financial Statements:



		Page
Reports of Independent Registered Public Accounting Firm as of December 31, 2014 and 2013, and for the years ended December 31, 2014, 2013, and 2012		65
Consolidated Statements of Operations for the years ended December 31, 2014, 2013, and 2012		66
Consolidated Balance Sheets as of December 31, 2014 and 2013		67
Consolidated Statement of Cash Flows for the years ended December 31, 2014, 2013, and 2012		68
Consolidated Statement of Equity - Successor, for the period from inception to December 31, 2014		69
Consolidated Statement of Equity - Predecessor, for the periods from December 31, 2011 to August 13, 2013		70
Notes Accompanying the Consolidated Financial Statements		71

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

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheets and related consolidated statements of income, equity, and cash flows present fairly, in all material respects, the financial position of QEP Midstream Partners, LP at December 31, 2014 and December 31, 2013, and the results of its operations and its cash flows for the year ended December 31, 2014 and for the period from August 14, 2013 to December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 9, 2015

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated statements of income, equity, and cash flows for the year ended December 31, 2012 and for the period from January 1, 2013 to August 13, 2013 present fairly, in all material respects, the results or operations and cash flows of QEP Midstream Partners, LP Predecessor for the year 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. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 20, 2014

QEP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME



			Year Ended
			December 31, 2013
	Year Ended December 31, 2014		Period from August 14, 2013, through December 31, 2013		Period from January 1, 2013, through August 13, 2013			Year Ended December 31, 2012
	Successor		Successor		Predecessor			Predecessor
	(in millions, except per unit information)
Revenues
Gathering and transportation	$	117.9	$	46.1	$	92.9		$	151.3
Condensate sales	5.3		2.0		7.4			10.9
Total revenues	123.2		48.1		100.3			162.2
Operating expenses
Gathering	24.5		9.8		19.7			29.9
General and administrative	17.8		5.5		13.6			17.0
Taxes other than income taxes	2.0		0.8		1.3			3.1
Depreciation and amortization	32.0		11.7		25.0			39.8
Total operating expenses	76.3		27.8		59.6			89.8
Net loss from property sales	—		—		(0.5		)	—
Operating income	46.9		20.3		40.2			72.4
Other income	—		—

QEP Midstream Partners, LP 10-K