QEP Midstream Partners, LP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - QEP Midstream Partners, LP	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - QEP Midstream Partners, LP	qepm-2013630xex321.htm
EX-31.1 - EXHIBIT 31.1 - QEP Midstream Partners, LP	qepm-2013630xex311.htm
EX-31.2 - EXHIBIT 31.2 - QEP Midstream Partners, LP	qepm-2013630xex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2013



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number: 333-188487

QEP MIDSTREAM PARTNERS, LP

(Exact name of registrant as specified in its charter)



STATE OF DELAWARE		80-0918184
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1050 17^th Street, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

Registrant’s telephone number, including area code: (303) 672-6900

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 o No ý

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 o

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



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 o No ý

There were 26,705,000 common units, 26,705,000 subordinated units and 1,090,000 general partner units outstanding on August 31, 2013.

QEP Midstream Partners, LP

Form 10-Q for the Quarter Ended June 30, 2013

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			3

	ITEM 1.	FINANCIAL STATEMENTS	3

		UNAUDITED COMBINED STATEMENTS OF INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013 AND 2012	3

		UNAUDITED COMBINED BALANCE SHEETS AT JUNE 30, 2013 AND DECEMBER 31, 2012	4

		UNAUDITED COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2013 AND 2012	5

		UNAUDITED COMBINED STATEMENTS OF EQUITY AT JUNE 30, 2013 AND 2012	6

		UNAUDITED NOTES ACCOMPANYING THE COMBINED FINANCIAL STATEMENTS	7

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26

	ITEM 4.	CONTROLS AND PROCEDURES	27

PART II. OTHER INFORMATION			29

	ITEM 1.	LEGAL PROCEEDINGS	29

	ITEM 1A.	RISK FACTORS	29

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	29

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	30

	ITEM 4.	MINE SAFETY DISCLOSURES	30

	ITEM 5.	OTHER INFORMATION	30

	ITEM 6.	EXHIBITS	31

SIGNATURES			33

Explanatory Note

The information contained in this report relates to periods that ended prior to the completion of QEP Midstream Partners, LP's initial public offering ("IPO"), and prior to the effective dates of the agreements discussed herein. Consequently, the unaudited combined financial statements and related discussion of financial condition and results of operations contained in this report 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 our IPO and properties retained by our predecessor, we do not consider these 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 August 14, 2013), refer to QEP Midstream Partners, LP Predecessor. References in this report to "QEP Midstream Partners, LP" the "Partnership," "we," "our," "us," or like terms, when used in the present tense or prospectively (starting August 14, 2013), refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of these financial statements, “QEP” refers to QEP Resources, Inc. and its consolidated subsidiaries.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in millions)
Revenues
Gathering and transportation	$	37.1		$	37.1		$	73.7		$	74.0
Condensate sales	3.0			2.6			6.5			7.6
Total revenues	40.1			39.7			80.2			81.6
Operating expenses
Gathering	8.3			6.7			16.0			13.9
General and administrative	4.7			4.1			10.4			7.7
Taxes other than income taxes	0.6			0.8			0.9			1.6
Depreciation and amortization	9.8			9.9			20.1			19.7
Total operating expenses	23.4			21.5			47.4			42.9
Net loss from property sales	(0.1		)	—			(0.4		)	—
Operating income	16.6			18.2			32.4			38.7
Income from unconsolidated affiliates	2.1			1.3			3.4			3.2
Interest expense	(1.0		)	(2.2		)	(2.1		)	(4.0		)
Net income	17.7			17.3			33.7			37.9
Net income attributable to noncontrolling interest	(1.3		)	(0.9		)	(1.9		)	(1.7		)
Net income attributable to Predecessor	$	16.4		$	16.4		$	31.8		$	36.2

See notes accompanying the combined financial statements.

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED BALANCE SHEETS

(Unaudited)



	June 30, 2013		December 31, 2012
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	3.1	$	1.4
Accounts receivable, net	19.2		18.2
Accounts receivable from related party	22.1		24.9
Natural gas imbalance receivable	2.4		2.2
Other current assets	0.8		0.1
Total current assets	47.6		46.8
Property, plant and equipment, net	618.5		634.1
Investment in unconsolidated affiliates	40.0		40.7
Accounts receivable, noncurrent	—		3.8
Total assets	$	706.1	$	725.4
LIABILITIES
Current liabilities:
Accounts payable	$	4.1	$	6.3
Accounts payable to related party	4.5		3.7
Natural gas imbalance liability	2.4		2.2
Deferred revenue	6.7		0.3
Accrued compensation	0.9		1.7
Other current liabilities	2.2		1.3
Total current liabilities	20.8		15.5
Long-term debt to related party	87.4		131.1
Asset retirement obligation	16.8		16.3
Deferred revenue	6.5		10.2
Total long-term liabilities	110.7		157.6
Commitments and contingencies (see Note 6)
EQUITY
Parent net investment	528.1		504.6
Noncontrolling interest	46.5		47.7
Total net equity	574.6		552.3
Total liabilities and equity	$	706.1	$	725.4

See notes accompanying the combined financial statements.

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2013			2012
	(in millions)
OPERATING ACTIVITIES
Net income	$	33.7		$	37.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	20.1			19.7
Income from unconsolidated affiliates	(3.4		)	(3.2		)
Distributions from unconsolidated affiliates	4.1			3.5
Net loss from asset sales	0.4			—
Changes in operating assets and liabilities:
Accounts receivable	7.7			2.0
Accounts payable and accrued expenses	4.4			(2.5		)
Other	(3.6		)	5.8
Net cash provided by operating activities	63.4			63.2
INVESTING ACTIVITIES
Property, plant and equipment	(7.5		)	(24.8		)
Proceeds from sale of assets	0.9			—
Net cash used in investing activities	(6.6		)	(24.8		)
FINANCING ACTIVITIES
Repayments of long-term debt to related party	(43.7		)	(28.4		)
Contributions from (distributions to) parent, net	(8.3		)	(3.9		)
Distribution to noncontrolling interest	(3.1		)	(3.1		)
Net cash used in financing activities	(55.1		)	(35.4		)
Change in cash and cash equivalents	1.7			3.0
Beginning cash and cash equivalents	1.4			2.5
Ending cash and cash equivalents	$	3.1		$	5.5

Supplemental Disclosures:
Non-cash investing activities
Change in capital expenditure accrual balance	$	(2.3	)	$	(3.6	)

See notes accompanying the combined financial statements.

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

COMBINED STATEMENTS OF EQUITY

(Unaudited)



	Parent Net Investment			Noncontrolling Interest			Total Net Equity
Balance at December 31, 2011	$	451.8		$	50.6		$	502.4
Net income for the six months ended June 30, 2012	36.2			1.7			37.9
Contributions from (distributions to) parent, net	(3.9		)	—			(3.9		)
Distribution of noncontrolling interest	—			(3.1		)	(3.1		)
Balance at June 30, 2012	$	484.1		$	49.2		$	533.3

Balance at December 31, 2012	$	504.6		$	47.7		$	552.3
Net income for the six months ended June 30, 2013	31.8			1.9			33.7
Contributions from (distributions to) parent, net	(8.3		)	—			(8.3		)
Distribution of noncontrolling interest	—			(3.1		)	(3.1		)
Balance at June 30, 2013	$	528.1		$	46.5		$	574.6

See notes accompanying the combined financial statements.

QEP MIDSTREAM PARTNERS, LP PREDECESSOR

NOTES ACCOMPANYING THE COMBINED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Description of Business and Basis of Presentation

Description of Business

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

The Predecessor consists of all of QEP's gathering assets in the Green River, Uinta and Williston Basins including a 100% interest in QEPM Gathering I, LLC and Rendezvous Pipeline Company, L.L.C. ("Rendezvous Pipeline"), a 78% interest in Rendezvous Gas Services, L.L.C. ("Rendezvous Gas Services"), a 50% equity interest in Three Rivers Gathering, L.L.C. ("Three Rivers Gathering"), a 38% equity interest in Uintah Basin Field Services, L.L.C. ("Uintah Basin Field Services") and a 100% interest in all other gathering assets of QEP in the Uinta Basin (collectively referred to as the "Uinta Basin Gathering System").

The Partnership was formed in Delaware on April 19, 2013, and following the Offering, owns certain operations and assets of the Predecessor. The Partnership's primary assets consist of ownership interests in four gathering systems and two Federal Energy Regulatory Commission ("FERC") regulated pipelines through which we provide natural gas and crude oil gathering and transportation services in Colorado, North Dakota, Utah and Wyoming. As part of the Offering, QEP Midstream Partners GP, LLC (the "General Partner") and QEP Field Services Company ("Field Services"), both QEP affiliates, collectively contributed to the Partnership (i) a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the "Operating Company"), QEPM Gathering I, LLC and Rendezvous Pipeline, (ii) a 78% interest in Rendezvous Gas Services, and (iii) a 50% equity interest in Three Rivers Gathering. The General Partner serves as the general partner of the Partnership and together with QEP provides services to the Partnership pursuant to an omnibus agreement and a service agreement between the parties. The Partnership's assets do not include the Uinta Basin Gathering System, which is included in the Predecessor's assets.

Basis of Presentation

The unaudited combined financial statements and accompanying notes relate to periods that ended prior to the completion of the Offering and prior to the effective dates of the agreements discussed herein, and therefore, pertain to the Predecessor. While management believes that the financial statements contained in this report are prepared in accordance with accounting principles generally accepted in the United States ("GAAP"), management does not believe that these financial statements are necessarily indicative of the financial statements that will be reported by the Partnership for periods subsequent to the Offering and other transactions that resulted in the capitalization and start-up of the Partnership. See "Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting the Comparability of Our Financial Results" within this report 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 Offering.

Interim combined financial statements are unaudited and do not include all of the information and notes required by GAAP for audited combined financial statements. These financial statements should be read in conjunction with the Predecessor's audited combined financial statements for the year ended December 31, 2012, included in our Prospectus related to the Offering dated August 8, 2013, (our "Prospectus") as filed with the Securities and Exchange Commission ("SEC"). These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the Predecessor's results of operations and financial position. Amounts reported in the Unaudited Combined Statements of Income are not necessarily indicative of amounts expected for the respective annual periods.

The unaudited combined financial statements of the Predecessor have been prepared in accordance with GAAP on the basis of QEP's historical ownership of the Predecessor assets. These combined financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have

occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net investment, in lieu of owner's equity, in the unaudited combined financial statements.

The Predecessor's costs of doing business incurred by QEP on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses charged as a management services fee by QEP to the Predecessor in exchange for:


•	business services, such as payroll, accounts payable and facilities management;


•	corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;


•	executive compensation, including share-based compensation; and


•	pension and other post-retirement benefit costs.

Transactions between the Predecessor and QEP have been identified in the combined financial statements as transactions between affiliates (see Note 3).

Note 2 - Summary of Significant Accounting Policies

Investment in Unconsolidated Affiliates

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

The unconsolidated affiliates of the Predecessor and the ownership percentage as of June 30, 2013, and December 31, 2012, were Uintah Basin Field Services (38%) and Three Rivers Gathering (50%). Both limited liability companies are engaged in the gathering and compression of natural gas.

Noncontrolling Interests

The Predecessor has a 78% interest in Rendezvous Gas Services, a joint venture with Western Gas Partners, LP ("Western Gas"), which owns a gas gathering system. The Predecessor consolidates Rendezvous Gas Services under the voting interest model. The Predecessor presents Western Gas' non-controlling interest on the Unaudited Combined Statements of Income and Unaudited Combined Balance Sheets accordingly.

Use of Estimates

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

Recent Accounting Developments

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

Note 3 - Related Party Transactions

The Predecessor provides natural gas gathering, compression, treating and transportation services to QEP resulting in affiliate transactions.

Centralized Cash Management

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

Affiliated Debt

The Predecessor's long-term debt consists of an allocation from Field Services of its total long-term debt outstanding related to Field Services' debt agreements with QEP. During the first quarter of 2012, Field Services had a $250.0 million revolving debt agreement (the "2011 Agreement") with QEP for its working capital requirements, in which Field Services was charged a variable interest rate. Interest during the first quarter of 2012 was allocated to the Predecessor based on an interest rate equal to QEP's average borrowing rate, which was 5.2% in the first quarter of 2012. In April 2012, Field Services entered into new debt agreements with QEP replacing the 2011 Agreement with a $250.0 million promissory note, which matured at the end of the first quarter of 2013 with a fixed interest rate of 6.05%. The promissory note was renewed on April 1, 2013, with a maturity date of April 1, 2014. In addition, Field Services entered into a $1.0 billion "revolving credit" type promissory note with QEP, which matures on April 1, 2017, to assist with funding of capital expenditures. Accordingly, all amounts have been classified as "Long-term debt to related party" in our Unaudited Combined Balance Sheets. Both agreements require Field Services to pay QEP interest during the last nine months of 2013 at a 6.0% fixed rate. Interest allocated to the Predecessor under these notes in the first quarter of 2013 was based on the fixed-rate due to QEP. Field Services was in compliance with its covenants under the agreements at June 30, 2013, and there are no letters of credit outstanding. At June 30, 2013, and December 31, 2012, allocated debt outstanding for the Predecessor was $87.4 million and $131.1 million, respectively.

Allocation of Costs

The employees supporting the Predecessor's operations are employees of QEP. General and administrative expenses allocated to the Predecessor were $4.7 million and $10.4 million for the three and six months ended June 30, 2013, respectively, and $4.1 million and $7.7 million for the three and six months ended June 30, 2012, respectively. The combined financial statements of the Predecessor include direct charges for operations of our assets and costs allocated by QEP. These costs are reimbursed and relate to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) compensation, share-based compensation, benefits and pension and post-retirement costs. These expenses were charged or allocated to the Predecessor based on the nature of the expenses and its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies are reasonable.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in millions)						(in millions)
Revenues from affiliate	$	20.6		$	19.2		$	41.3		$	37.6
Interest expense to affiliate	(1.0		)	(2.2		)	(2.1		)	(4.0		)

Note 4 - Property, Plant and Equipment

A summary of the historical cost of the Predecessor's property, plant and equipment is as follows:



	Estimated Useful Lives	June 30, 2013			December 31, 2012
		(in millions)
Gathering equipment	5 to 40 years	$	907.2		$	907.7
General support equipment	3 to 30 years	11.8			11.1
Total property, plant and equipment		919.0			918.8
Accumulated depreciation		(300.5		)	(284.7		)
Total net property, plant and equipment		$	618.5		$	634.1

Note 5 - Asset Retirement Obligations

The Predecessor records asset retirement obligations ("ARO") when there are legal obligations associated with the retirement of tangible long-lived assets. The fair values of such costs are estimated by our personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO liability may occur due, among other things, to changes in estimated abandonment costs and estimated settlement timing. The ARO liability is adjusted to present value each period through an accretion calculation using our credit-adjusted, risk-free interest rate.

The following is a reconciliation of the changes in the ARO liability for the periods specified below:



	Asset Retirement Obligations
	2013
	(in millions)
ARO liability at January 1,	$	16.3
Accretion	0.5
ARO liability at June 30,	$	16.8

Note 6 - Commitments and Contingencies

We are involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of our business. We assess these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in our combined financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Predecessor's litigation loss contingencies are discussed below. We are unable to estimate reasonably possible losses in excess of recorded accruals for these contingencies for the reasons set forth above. We believe, however, that the resolution of pending proceedings will not have a material effect on our financial position, results of operations or cash flows.

Litigation

Our gathering systems are the subject of ongoing litigation between Questar Gas Company ("QGC") and Field Services, styled Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. Field Services' former affiliate, QGC, filed this complaint in state court in Utah on May 1, 2012, asserting claims for (i) breach of contract, (ii) breach of implied covenant of good faith and fair dealing, (iii) an accounting and (iv) declaratory judgment related to a 1993 gathering agreement and a 1998 amendment (the "1993 Agreement") executed when the parties were affiliates. Under the 1993 Agreement, Field Services provides gathering services to QGC charging an annual gathering rate which is based on cost of service. QGC is disputing the calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. QGC is netting the disputed amount from its monthly payment of the gathering fees to Field Services and

as of June 30, 2013, our Predecessor has deferred revenue of $5.8 million related to the QGC disputed amount. Specific monetary damages are not asserted. Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the same agreement. The parties have agreed to attempt to settle the case by participating in non-binding mediation. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. The 1993 Agreement has been assigned to the Partnership by Field Services. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined below in "Note 7 - Subsequent Events"). Management does not believe the litigation will have a material adverse effect on our financial position, results of operations, or cash flows.

Note 7 - Subsequent Events

Initial Public Offering

On August 14, 2013, the Partnership completed the Offering of 20,000,000 common units, representing limited partner interests in the Partnership, at a price to the public of $21.00 per common unit. The Partnership received net proceeds of $389.7 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and estimated offering expenses of approximately $30.3 million. Following the Offering, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit, providing an additional $63.0 million in cash ($58.9 million net of underwriters' discounts and commissions of $4.1 million) to the Partnership. The Partnership used the net proceeds to repay its outstanding debt balance with QEP, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to the Partnership.

Contribution, Conveyance and Assumption Agreement

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


•	Field Services contributed to the General Partner, as a capital contribution, a limited liability company interest in the Operating Company with a value equal to 2% of the equity value of the Partnership at the closing of the Offering;


•	the General Partner contributed to the Partnership, as a capital contribution, the limited liability company interest in the Operating Company in exchange for (a) 1,090,000 general partner units representing the continuation of an aggregate 2% general partner interest in the Partnership and (b) all the incentive distribution rights of the Partnership;

•

Field Services contributed to the Partnership, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner interest in the Partnership, (b) 26,705,000 subordinated units representing a 49% limited partner interest in the Partnership and (c) the right to receive a distribution from the partnership; and


•	the public, through the underwriters, contributed $420.0 million in cash (or $389.7 million, net of the underwriters' discounts and commissions, structuring fees and estimated offering expenses of approximately $30.3 million) to the Partnership in exchange for the issuance of 20,000,000 common units.

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

Omnibus Agreement

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

•

the Partnership's payment of an annual amount to QEP, initially in the amount of approximately $13.8 million, for the provision of certain general and administrative services by QEP and its affiliates to the Partnership, including a fixed annual fee of approximately $1.4 million for providing certain executive management services by certain officers of the General Partner. The remaining portion of this annual amount reflects an estimate of the costs QEP and its affiliates expect to incur in providing the services;

•

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


•	an indemnity by QEP for certain environmental and other liabilities, and the Partnership's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of the Partnership's assets that occur after the closing of the Offering and for environmental liabilities related to the Partnership's assets to the extent QEP is not required to indemnify it.

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

Fixed Price Condensate Purchase Agreement

On August 14, 2013, the Partnership entered into a fixed price Condensate Purchase Transaction Agreement (the "Condensate Purchase Agreement") with QEP. The Condensate Purchase Agreement has a primary term of five years and allows us to sell the condensate volumes collected on our gathering systems to QEP at a fixed price of $85.25 per barrel.

Credit Facility

On August 14, 2013, in connection with the closing of the Offering, we entered into a $500.0 million senior secured revolving credit facility (the "Credit Facility") with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders, which will mature on August 14, 2018. The Credit Facility will be available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. In addition, the Credit Facility includes a sublimit up to $50.0 million for letters of credit and a sublimit up to $25.0 million for swing line loans. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for transactions of this nature.

Loans under the Credit Facility will bear interest at the Partnership's option at a variable rate per annum equal to either:


•	a base rate, which will be the highest of (i) the administrative agent's prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or


•	LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio.

2013 Long-Term Incentive Plan

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

The LTIP provides for the grant, from time to time at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the LTIP to 5,341,000 common units. Common units cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP will be administered by the Board or a designated committee thereof. On August 14, 2013, the Partnership granted 3,250 common units to our independent director and 39,500 phantom units with dividend equivalent rights to employees including executive officers.

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

On August 14, 2013, in connection with the closing of the Offering, the Agreement of Limited Partnership was amended and restated by the First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP (as amended and restated, the "Partnership Agreement"). A description of the Partnership Agreement is contained in our Prospectus in the section entitled "Our Partnership Agreement."

Green River Gathering System

During the third quarter of 2013, we experienced minor condensate pipeline leaks in our Green River Gathering System. QEP has indemnified the Partnership through the Omnibus Agreement for any associated capital costs and expenses related to this issue. The pipeline leaks did not result in significant disruptions to our operations and are expected to be fully repaired in the by the end of 2013.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited historical combined financial statements and notes in "Item 1. Financial Statements" contained herein and the Predecessor's audited combined financial statements for the year ended December 31, 2012, included in our Prospectus. Among other things, those historical combined financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below as a result of various risk factors, including those that may not be in the control of management. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included in our Prospectus. See also "Forward-Looking Statements" in Item 3 of this report.

Overview

QEP Midstream Partners, LP (NYSE: QEPM) is a limited partnership recently formed by QEP Resources, Inc. (NYSE: QEP) to own, operate, acquire and develop midstream energy assets. Our primary assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota and consist of the following assets:


•	Green River System


◦	Green River Gathering Assets. The Green River Gathering Assets are comprised of 376 miles of natural gas gathering pipelines, 56 miles of crude oil gathering pipelines, 84 miles of water gathering pipelines and a 61-mile, FERC-regulated crude oil pipeline located in the Green River Basin.

◦

Rendezvous Gas. Rendezvous Gas is a joint venture between QEP and Western Gas, which was formed to own and operate the infrastructure that transports gas from the Pinedale and Jonah fields to several re-delivery points, including natural gas processing facilities that are owned by QEP or Western Gas. The Rendezvous Gas assets consist of three parallel, 103-mile high-pressure natural gas pipelines, with 1,032 MMcf/d of aggregate throughput capacity and 7,800 bhp of gas compression. We own a 78% interest in Rendezvous Gas.


◦	Rendezvous Pipeline. Rendezvous Pipeline's sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEP's Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 460 MMcf/d.


•	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 518 miles of low-pressure, gas gathering pipelines and 23,197 bhp of gas compression. The Vermillion Gathering System has combined total throughput capacity of 206 MMcf/d.

•

Three Rivers Gathering System. Three Rivers Gathering is a joint venture between QEP and Ute Energy Midstream Holdings, LLC that was formed to transport natural gas gathered by Uintah Basin Field Services, an indirectly owned subsidiary in which QEP owns a 38% interest, and other third-party volumes to gas processing facilities owned by QEP and third parties. The Three Rivers Gathering System consists of gas gathering assets located in the Uinta Basin in northeast Utah, including approximately 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.

•

Williston Gathering System. The Williston Gathering System is a crude oil and natural gas gathering system located in the Williston Basin in McLean County, North Dakota. The Williston Gathering System includes 15 miles of gas gathering pipelines, 15 miles of oil gathering pipelines, 239 bhp of gas compression, and a crude oil and natural gas handling facility, located primarily on the Fort Berthold Indian Reservation. The Williston Gathering System has total crude oil throughput capacity of 7,000 Bbls/d.

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

The Results of Operations discussed below are for our Predecessor and include combined results for both the properties conveyed to the Partnership in connection with the Offering and the properties retained by our Predecessor. Under "Supplemental Disclosures" below, we have included historical data limited to only the properties conveyed to us in connection with the Offering, as we believe such data is more useful to the reader to better understand trends in our operations.

Our Operations

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

We generally do not take title to the oil and natural gas that we gather or transport. We provide all of our gathering services pursuant to fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Under these arrangements, we are paid a fixed or margin-based fee with respect to the volume of the oil and natural gas we gather. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. In addition to our fee-based gathering services, for the three and six months ended June 30, 2013, approximately 7% and 8%, respectively, of our Predecessor's revenue was generated through the sale of condensate volumes that we collect on our gathering systems. Although the Partnership has entered into a fixed price condensate sales agreement with QEP, we still have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of oil and natural gas available for gathering by our systems. Please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

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

We provide a portion of our gathering and transportation services on our Three Rivers, Vermillion and Williston Gathering Systems through firm contracts with minimum volume commitments, which are designed to ensure that we will generate a certain amount of revenue over the life of the gathering agreement by collecting either gathering fees for actual throughput or payments to cover any shortfall. Our Predecessor's and our largest customer is QEP, which accounted for approximately 51% of our Predecessor's total revenues for both the three and six months ended June 30, 2013. For a discussion regarding our minimum volume commitments, please read "Business — Our Assets and Operations — Minimum Volume Commitments" within our Prospectus.

How We Evaluate Our Business

Our management uses a variety of financial and operating metrics to analyze our performance including: (i) throughput volumes; (ii) gathering expenses; (iii) Adjusted EBITDA; and (iv) distributable cash flow.

Throughput volumes

The amount of revenue we generate primarily depends on the volumes of natural gas and crude oil that we gather for our customers. The volumes transported on our gathering pipelines are driven by upstream development drilling activity and production volumes from the wells connected to our gathering pipelines. Producers' willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of oil, natural gas and natural gas liquids ("NGLs"), the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in natural gas, oil

and NGL prices.

Gathering expenses

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

Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We define Adjusted EBITDA as net income attributable to our Predecessor before depreciation and amortization, interest and other income and expense, gains and losses from asset sales and deferred revenue associated with minimum volume commitment payments. Although we have not quantified distributable cash flow on a historical basis, we will use distributable cash flow, which we define as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity method investments and non-controlling interests, to analyze our performance. Distributable cash flow will not reflect changes in working capital balances. Adjusted EBITDA and distributable cash flow are non-GAAP, supplemental financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:


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


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


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


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

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

General Trends and Outlook

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

Oil and natural gas supply and demand

Our gathering operations are primarily dependent upon oil and natural gas production from the upstream sector in our areas of operation. The decline in natural gas prices over the prior years has caused a related decrease in natural gas drilling in the United States. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. However, in the areas in which we operate, there remains a consistent level of drilling activity due to the liquids content of the natural gas, that we believe will offset the production and drilling declines seen in other areas. Although we anticipate continued high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in oil and natural gas prices could affect production rates over time and levels of investment by QEP and third parties in exploration for and development of new oil and natural gas reserves. During 2012, QEP operated six drilling rigs in the Pinedale Field, but in 2013 QEP reduced the number of operated rigs to four. Although the rig count is currently lower than the rig count in 2012, QEP expects to complete approximately the same number of wells for the

year ended December 31, 2013, as it did for the year ended December 31, 2012, as a result of the inventory of wells drilled but not yet completed at the beginning of the year and more efficient drilling and completion operations. We expect a slight decline in production from the Pinedale Field resulting from the reduced rig count. Please read "Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations" within our Prospectus.

Rising operating costs and inflation

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

Impact of interest rates

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

Regulatory compliance

The regulation of oil and natural gas gathering and 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 oil and natural gas. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems. For more information see "Business — Regulation of the Industry and Our Operations as to Rates and Terms and Conditions of Service" included in our Prospectus.

Acquisition opportunities

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

Factors Affecting the Comparability of Our Financial Results

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

Assets not included in our partnership

Our Predecessor's results of operations prior to the Offering include revenues and expenses relating to QEP's ownership of the Uinta Basin Gathering System and general support equipment. QEP did not contribute an interest in these assets to us in connection with the Offering.

General and administrative expenses

For the three and six months ended June 30, 2013, we incurred $4.7 million and $10.4 million, respectively, in general and administrative expenses. Our Predecessor's general and administrative expenses included costs allocated by QEP. These costs were reimbursed and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources, and (iii) compensation, share-based compensation, benefits and pension and post-retirement costs. General, administrative and management costs were allocated to the Predecessor based on its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable. Subsequent to the Offering, QEP will charge us a combination of direct and allocated charges for administrative and operational services.

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

Working capital

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

Interest expense

Prior to the Offering, we incurred interest expense on intercompany notes payable to QEP that was allocated to us. These balances were repaid with a portion of the proceeds from the Offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in the future. Upon the closing of the Offering, we entered into a $500 million revolving credit facility agreement, which provides for customary short-term interest rates. See "Results of Operations - Liquidity and Capital Resources - Credit Facility" below.

Cash distributions to unitholders

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

Results of Operations

The following table compares the results of our Predecessor's operations for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,											Six Months Ended June 30,
	2013			2012			$ change			% change		2013			2012			$ change			% change
	(in millions, except operating and per unit amounts)
Revenues
Gathering and transportation	$	37.1		$	37.1		$	—		—	%	$	73.7		$	74.0		$	(0.3	)	—	%
Condensate sales	3.0			2.6			0.4			15	%	6.5			7.6			(1.1		)	(14	)%
Total revenues	40.1			39.7			0.4			1	%	80.2			81.6			(1.4		)	(2	)%
Operating expenses
Gathering expenses	8.3			6.7			1.6			24	%	16.0			13.9			2.1			15	%
General and administrative	4.7			4.1			0.6			15	%	10.4			7.7			2.7			35	%
Taxes other than income taxes	0.6			0.8			(0.2		)	(25	)%	0.9			1.6			(0.7		)	(44	)%
Depreciation and amortization	9.8			9.9			(0.1		)	(1	)%	20.1			19.7			0.4			2	%
Total operating expenses	23.4			21.5			1.9			9	%	47.4			42.9			4.5			10	%
Net loss from property sales	(0.1		)	—			(0.1		)			(0.4		)	—			(0.4		)
Operating income	16.6			18.2			(1.6		)	(9	)%	32.4			38.7			(6.3		)	(16	)%
Income from unconsolidated affiliates	2.1			1.3			0.8			62	%	3.4			3.2			0.2			6	%
Interest expense	(1.0		)	(2.2		)	1.2			(55	)%	(2.1		)	(4.0		)	1.9			(48	)%
Net income	17.7			17.3			0.4			2	%	33.7			37.9			(4.2		)	(11	)%
Net income attributable to noncontrolling interest	(1.3		)	(0.9		)	(0.4		)	44	%	(1.9		)	(1.7		)	(0.2		)	12	%
Net income attributable to Predecessor	$	16.4		$	16.4		$	—		—	%	$	31.8		$	36.2		$	(4.4	)	(12	)%
Operating Statistics
Natural gas throughput in millions of MMBtu
Gathering and transportation	94.4			99.4			(5.0		)	(5	)%	185.0			192.5			(7.5		)	(4	)%
Equity interest⁽¹⁾	7.3			7.1			0.2			3	%	10.6			14.3			(3.7		)	(26	)%
Total natural gas throughput	101.7			106.5			(4.8		)	(5	)%	195.6			206.8			(11.2		)	(5	)%
Throughput attributable to noncontrolling interests⁽²⁾	(2.7		)	(3.6		)	0.9			(25	)%	(5.3		)	(7.0		)	1.7			(24	)%
Total throughput attributable to our Predecessor	99.0			102.9			(3.9		)	(4	)%	190.3			199.8			(9.5		)	(5	)%
Crude oil and condensate gathering system throughput volumes (in MBbls)	1,380.8			1,408.9			(28.1		)	(2	)%	2,659.6			2,731.3			(71.7		)	(3	)%
Water gathering volumes (in MBbls)	1,027.6			944.4			83.2			9	%	1,897.7			1,852.0			45.7			2	%
Condensate sales volumes (in MBbls)	36.2			30.4			5.8			19	%	78.9			85.5			(6.6		)	(8	)%
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.34		$	0.33		$	0.01		3	%	$	0.34		$	0.33		$	0.01		3	%
Average oil and condensate gathering fee (per barrel)	$	2.14		$	2.05		$	0.09		4	%	$	2.45		$	2.36		$	0.09		4	%
Average water gathering fee (per barrel)	$	1.83		$	1.88		$	(0.05	)	(3	)%	$	1.82		$	1.84		$	(0.02	)	(1	)%
Average condensate sale price (per barrel)	$	80.96		$	83.84		$	(2.88	)	(3	)%	$	82.05		$	88.47		$	(6.42	)	(7	)%
Non-GAAP Measures
Adjusted EBITDA	$	27.0		$	27.8		$	(0.8	)	(3	)%	$	53.4		$	58.5		$	(5.1	)	(9	)%


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


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

Adjusted EBITDA

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in millions)
Reconciliation of Net Income Attributable to Our Predecessor to Adjusted EBITDA
Net income attributable to our Predecessor	$	16.4		$	16.4		$	31.8		$	36.2
Interest expense	1.0			2.2			2.1			4.0
Depreciation and amortization⁽¹⁾	9.5			9.2			19.1			18.3
Net loss from asset sales	0.1			—			0.4			—
Adjusted EBITDA	$	27.0		$	27.8		$	53.4		$	58.5
Reconciliation of Net Cash Flows Provided by Operating Activities to Adjusted EBITDA
Net cash provided by operating activities	$	24.5		$	26.6		$	63.4		$	63.2
Noncontrolling interest share of depreciation and amortization	(0.3		)	(0.7		)	(1.0		)	(1.4		)
Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates	(0.5		)	(0.7		)	(0.7		)	(0.3		)
Net income attributable to noncontrolling interest	(1.3		)	(0.9		)	(1.9		)	(1.7		)
Interest expense	1.0			2.2			2.1			4.0
Working capital changes	3.6			1.3			(8.5		)	(5.3		)
Adjusted EBITDA	$	27.0		$	27.8		$	53.4		$	58.5


(1)	Excludes the noncontrolling interest's 22% share, or $0.3 million and $0.7 million during the three months ended June 30, 2013 and 2012, respectively, and $1.0 million and $1.4 million during the six months ended June 30, 2013 and 2012, respectively, in depreciation and amortization attributable to Rendezvous Gas Services.

Three Months Ended June 30, 2013, compared to Three Months Ended June 30, 2012

Revenue, Volume and Price Variance Analysis

Gathering and transportation. Gathering and transportation revenues were flat in the second quarter of 2013 due to increased water gathering revenue of $0.1 million offset by a decrease in natural gas gathering revenues of $0.1 million. Natural gas gathering revenues decreased in the second quarter of 2013 due to a decrease in natural gas gathering volumes of 5% partially offset by an increase in the average natural gas gathering rate. Natural gas gathering volumes were 5.0 million MMBtu lower in the second quarter of 2013 primarily due to a 4.5 million MMBtu decline in Rendezvous Gas system throughput from lower third party volumes as well as a 2.2 million MMBtu decline in Uinta Basin Gathering System and a 0.7 million MMBtu decline in the Vermillion Gathering System throughput, both from declines in upstream drilling activity. These decreases were partially offset by a 2.3 million MMBtu increase in natural gas gathering volumes in our Green River Gathering System due to an increase in QEP's Pinedale production. Our average natural gas gathering rate increased due to higher revenues from natural gas deficiency revenues recognized in the second quarter of 2013 in the Uinta Basin Gathering System. Deficiency payments are recognized as revenue if a customer's actual throughput volumes are less than its contractual minimum volume commitment for the applicable period. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering fee. Please read the "Business — Our Assets and Operations — Minimum Volume Commitments" section within our Prospectus.

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

Condensate sales. Revenues from condensate sales increased $0.4 million, or 15%, due to a 19% increase in condensate sales volumes partially offset by a 3% decrease in condensate sales price. Condensate sales volumes increased 17% on our Green River Gathering System.

Operating Expenses

Gathering expenses. Gathering expenses increased $1.6 million, or 24%, in the second quarter of 2013 primarily due to an increase in labor and benefits costs. Labor and benefits increased due to additional compensation costs from QEP's annual incentive program, which were allocated to the Predecessor by QEP.

General and administrative. General and administrative expenses increased $0.6 million, or 15%, in the second quarter of 2013 due to increases in headcount and additional compensation costs from QEP's annual incentive program and the related allocation of direct and indirect costs to the Predecessor.

Taxes other than income taxes. Taxes other than income taxes decreased $0.2 million in the second quarter of 2013 primarily due to a property tax refund in the second quarter of 2013 related to our Vermillion Gathering System.

Depreciation and amortization. Depreciation and amortization expense decreased 1% in the second quarter of 2013 compared to 2012 primarily due to a decrease in depreciation and amortization expense in our Rendezvous Gas System partially offset by increases at our Vermillion, Green River and Williston Gathering Systems. The increase in depreciation and amortization expense in the Vermillion Gathering System was due to a stabilizer placed into service during the last half of 2012. The increases in the Green River and Williston Gathering Systems depreciation and amortization expense primarily related to additional gathering equipment placed into service during the last quarter of 2012. Rendezvous Gas System depreciation and amortization expense decreased in the current quarter due to less accretion expense.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased $0.8 million, or 62%, in the second quarter of 2013 due to a $0.5 million increase in our Predecessor's share of the Uintah Basin Field Services partnership net income and a $0.3 million increase in our Predecessor's share of the Three Rivers Gathering partnership net income due to higher deficiency revenues recognized in 2013, partially offset by decreased gathering volumes in 2013.

Interest expense. Interest expense decreased $1.2 million, or 55%, in the second quarter of 2013 due to a decrease in outstanding average debt balances with QEP. Average debt outstanding in the second quarter of 2013 was $86.5 million compared to $152.9 million in the second quarter of 2012.

Six Months Ended June 30, 2013, compared to Six Months Ended June 30, 2012

Revenue, Volume and Price Variance Analysis

Gathering and transportation. Gathering and transportation revenues decreased $0.3 million in the first half of 2013 due to a $0.3 million decrease in natural gas gathering revenues. Natural gas gathering revenues were lower in the first half of 2013 due to a 7.5 million MMBtu decrease in natural gas gathering volumes partially offset by a 3% increase in average gathering fees per MMBtu. Natural gas gathering volumes decreased primarily due to a 7.9 million MMBtu decrease in Rendezvous Gas System throughput due to lower third party volumes, a 2.4 million MMBtu decline in the Uinta Basin Gathering System and a 1.0 million MMBtu decline in Vermillion Gathering System throughput due to a decline in upstream drilling activity. These decreases were partially offset by an increase in natural gas gathering throughput in the Green River Gathering System of 3.7 million MMBtu due to an increase in QEP's Pinedale production.

Condensate sales. Revenues from condensate sales decreased $1.1 million, or 14%, due to a decrease in condensate sales volumes of 8% and a decrease in price of 7%. Condensate sales volumes decrease was primarily attributable to our Green River Gathering System due to a new contract with QEP, which allows QEP to retain its proportionate share of condensate volumes. The decrease in price per barrel in the first half of 2013 was primarily attributable to a decrease in the NYMEX crude oil price and additional lower quality condensate, which is priced at a discount.

Operating Expenses

Gathering expenses. Gathering expenses increased $2.1 million, or 15%, in the first half of 2013 primarily due to an increase in labor and benefits costs. Labor and benefits increased due to additional compensation costs from QEP's annual incentive program, which were allocated to the Predecessor by QEP.

General and administrative. General and administrative expenses increased $2.7 million, or 35%, in the first six months of 2013 due to increases in headcount and related compensation costs and the related allocation of direct and indirect costs to the Predecessor.

Taxes other than income taxes. Taxes other than income taxes decreased $0.7 million, or 44%, in the first half of 2013 primarily due to a decrease in property taxes related to our Predecessor's Uinta Basin Gathering System.

Depreciation and amortization. Depreciation and amortization expense increased $0.4 million, or 2%, in the first six months of 2013 primarily due to increases at our Vermillion, Green River Basin and Williston Gathering Systems of $0.2 million, $0.2 million and $0.3 million, respectively, partially offset by a decrease in depreciation and amortization expense at our Rendezvous Gas System. The increase in the Vermillion Gathering System depreciation and amortization expense was due to a stabilizer placed into service during the last half of 2012. The increase in depreciation and amortization expense in the Green River and Williston Gathering Systems primarily related to additional gathering equipment placed into service during the last quarter of 2012. Rendezvous Gas System depreciation and amortization expense decreased in the first half of 2013 due to less accretion expense.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased $0.2 million, or 6%, in the first half of 2013 due to a $0.5 million increase in our Predecessor's share of net income from the Uintah Basin Field Services partnership offset by a $0.3 million decrease in our Predecessor's share of net income from Three Rivers Gathering due to the recognition of deficiency charges in 2012.

Interest expense. Interest expense decreased $1.9 million, or 48%, in the first half of 2013 due to a decrease in outstanding average debt balances with QEP. Average debt outstanding in the first half 2013 was $109.2 million compared to $160.4 million in the first six months of 2012.

Liquidity and Capital Resources

Historically, our sources of liquidity included cash generated from operations and funding from QEP. We historically participated in QEP's centralized cash management program for all periods presented, under which the net balance of our cash receipts and cash disbursements were settled with QEP on a periodic basis. Prospectively, we will maintain our own bank accounts and sources of liquidity and will utilize QEP's cash management system and expertise.

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

Cash Flow

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



	Six Months Ended June 30,
	2013			2012			$ change			% change
	(in millions)
Net cash provided by (used in):
Operating activities	$	63.4		$	63.2		$	0.2		—	%
Investing activities	(6.6		)	(24.8		)	18.2			(73	)%
Financing activities	(55.1		)	(35.4		)	(19.7		)	56	%

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



	Six Months Ended June 30,
	2013		2012		$ change			% change
	(in millions)
Net income	$	33.7	$	37.9	$	(4.2	)	(11	)%
Non-cash adjustments to net income	21.2		20.0		1.2			6	%
Changes in operating assets and liabilities	8.5		5.3		3.2			60	%
Net cash provided from operating activities	$	63.4	$	63.2	0.2			—	%

Our Predecessor's operating cash flows are primarily affected by non-cash adjustments to net income and changes in working capital. Net cash provided from operating activities increased $0.2 million in the first half of 2013 due to changes in our working capital, increased non-cash adjustments to net income due to increased depreciation and amortization expense and distribution from unconsolidated affiliates partially offset by a decrease in net income.

Investing Activities. Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. Our Predecessor's total historical capital expenditures are presented in the following table:



	Six Months Ended June 30,
	2013		2012		$ change			% change
	(in millions)
Total accrual capital expenditures	$	5.2	$	21.2	$	(16.0	)	(75	)%
Change in accruals and non-cash items	2.3		3.6		$	(1.3	)	(36	)%
Total cash capital expenditures	$	7.5	$	24.8	$	(17.3	)	(70	)%

Our Predecessor's historical capital expenditures were funded from a combination of cash flow generated from operations and funding from QEP. Our Predecessor's capital investment decreased $17.3 million, to $7.5 million in the first six months of

2013, compared to $24.8 million in the first six months of 2012, due primarily to higher 2012 capital expenditures for the expansion of the Williston Gathering System.

Financing Activities. Our Predecessor's cash used in financing activities in the first half of 2013 primarily consisted of $43.7 million in repayments of long-term debt to QEP compared to $28.4 million in the first half of 2012. In addition, our Predecessor had distributions to QEP of $8.3 million and distributions to its noncontrolling interest in Rendezvous Gas of $3.1 million in the first half of 2013.

Capital Requirements

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

•

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

•

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

We expect our Predecessor's capital expenditures for the year ending December 31, 2013 to be $59.2 million, of which $36.6 million relates to the Uinta Basin Gathering System and the remaining $22.6 million relates to the Partnership, of which $16.7 million relates to maintenance capital expenditures and the remaining $5.9 million for expansion capital. Of the $16.7 million maintenance capital, we expect to incur $8.0 million for new well connections, $2.0 million for compressor projects, $3.1 million for gathering system projects, and the remaining $3.6 million for various other projects. The expansion capital of $5.9 million provides $4.6 million for compressor projects and $1.3 million for a gas treatment facility. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our Credit Facility, the issuance of additional partnership units or debt offerings.

Distributions

We intend to pay a minimum quarterly distribution of $0.2500 per unit, which equates to $13.6 million per quarter, or $54.5 million per year, based on the number of common, subordinated and general partner units outstanding immediately after completion of the Offering. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions" within our Prospectus.

Credit Facility

On August 14, 2013, in connection with the closing of the Offering, we entered into the Credit Facility, a $500.0 million senior secured revolving credit agreement, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of lenders with a maturity date of August 14, 2018. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. In addition, the Credit Facility includes a sublimit up to $50.0 million for letters of credit and a sublimit up to $25.0 million for swing line loans. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains events of restrictions and

default customary for transactions of this nature.

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

Loans under the Credit Facility (other than swing line loans discussed below) will bear interest at the Partnership's option at a variable rate per annum equal to either:


•	a base rate, which will be the highest of (i) the administrative agent’s prime rate in effect on such day, (ii) the federal funds rate in effect on such day plus 0.50%, and (iii) one-month LIBOR plus 1.0%, in each case, plus an applicable margin ranging from 0.75% to 1.50% based on the Partnership's consolidated leverage ratio; or


•	LIBOR plus an applicable margin ranging from 1.75% to 2.50% based on the Partnership's consolidated leverage ratio.

Swing line loans will bear interest at (i) the federal funds rate plus an applicable margin ranging from 0.75% or to 1.50% based on the Partnership's consolidate leverage ratio or (ii) a rate to be established as provided in the Credit Facility, as selected by the borrower and specified in the swing line loan notice delivered by the borrower in connection with the loan.

The unused portion of the Credit Facility will be subject to a commitment fee ranging from 0.325% to 0.500% per annum.

We currently have borrowing capacity of approximately $400.0 million calculated in accordance with the provisions of our Credit Facility.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

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

Critical Accounting Policies and Estimates

As of June 30, 2013, there have been no significant changes to our critical accounting policies and estimates as disclosed in our Prospectus.

Supplemental Disclosures

As previously discussed, the information contained in this report relates to periods that ended prior to the completion of the Offering, and prior to the effective dates of the agreements discussed herein. Consequently, the results discussed above included combined results for both the properties conveyed to the Partnership in connections with the Offering and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to us in connection with the Offering is useful to the reader to better understand trends in our operations. The following information is for informational purposes only and should not be considered indicative of future results.

QEP Midstream Partners, LP Unaudited Pro Forma Financial Data

	Three Months Ended June 30,											Six Months Ended June 30,
	2013			2012			$ change			% change		2013			2012			$ change			% change
	(in millions, except operating and per unit amounts)
Revenues
Gathering and transportation	$	28.7		$	28.6		$	0.1		—	%	$	57.7		$	58.3		$	(0.6	)	(1	)%
Condensate sales	2.6			2.4			0.2			8	%	4.6			5.6			(1.0		)	(18	)%
Total revenues	31.3			31.0			0.3			1	%	62.3			63.9			(1.6		)	(3	)%
Operating expenses
Gathering expenses	5.8			4.8			1.0			21	%	11.6			10.1			1.5			15	%

Operating Statistics
Natural gas throughput in millions of MMBtu
Gathering and transportation	75.6			78.4			(2.8		)	(4	)%	148.1			153.2			(5.1		)	(3	)%
Equity interest⁽¹⁾	6.8			7.2			(0.4		)	(6	)%	9.7			11.9			(2.2		)	(18	)%
Total natural gas throughput	82.4			85.6			(3.2		)	(4	)%	157.8			165.1			(7.3		)	(4	)%
Throughput attributable to noncontrolling interests⁽²⁾	(2.7		)	(3.6		)	0.9			(25	)%	(5.3		)	(7.0		)	1.7			(24	)%
Total throughput attributable to our Predecessor	79.7			82.0			(2.3		)	(3	)%	152.5			158.1			(5.6		)	(4	)%
Crude oil and condensate gathering system throughput volumes (in MBbls)	1,380.8			1,408.9			(28.1		)	(2	)%	2,659.6			2,731.3			(71.7		)	(3	)%
Water gathering volumes (in MBbls)	1,027.6			944.4			83.2			9	%	1,897.7			1,852.0			45.7			2	%
Condensate sales volumes (in MBbls)	32.9			29.0			3.9			13	%	56.2			62.0			(5.8		)	(9	)%
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.32		$	0.31		$	0.01		3	%	$	0.32		$	0.32		$	—		—	%
Average oil and condensate gathering fee (per barrel)	$	2.14		$	2.05		$	0.09		4	%	$	2.45		$	2.36		$	0.09		4	%
Average water gathering fee (per barrel)	$	1.83		$	1.88		$	(0.05	)	(3	)%	$	1.82		$	1.84		$	(0.02	)	(1	)%
Average condensate sale price (per barrel)	$	80.94		$	83.93		$	(2.99	)	(4	)%	$	82.38		$	89.63		$	(7.25	)	(8	)%


⁽¹⁾	Includes our 50% share of gross volumes from Three Rivers Gathering.


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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

At June 30, 2013, our Predecessor's interest expense was an allocation of Field Service's interest expense on debt which consists of two promissory notes between Field Services and QEP, each with a fixed rate of 6.0%, which is not subject to interest rate movements. Our new Credit Facility contains a variable interest rate that exposes us to volatility in interest rates. However, at June 30, 2013, the Credit Facility was not in place and therefore we did not have any debt subject to floating interest rates.

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenues is dependent upon the price received for the condensate. Condensate historically sells at a price representing a slight discount to the price of 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, on August 14, 2013, the Partnership entered into a fixed price Condensate Purchase Agreement with QEP, which allows us to sell the condensate volumes collected on our gathering systems at a fixed price of $85.25 per barrel of product over a primary term of five years. In addition, we expect to utilize risk management tools to minimize future commodity price risk that could be associated with assets we may acquire or contracts we may enter into in the future.

Forward-Looking Statements

This quarterly report contains 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. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:


•	belief that the historical financial results of our Predecessor are not indicative of our future results;


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


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


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


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


•	our ability to maximize operating profits by minimizing operating and maintenance costs;


•	stability of operating and maintenance costs across broad ranges of throughput volumes;


•	fluctuation of operating and maintenance costs from period to period;


•	anticipated general and administrative expenses following the Offering;


•	Adjusted EBITDA;


•	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 Pinedale Field;


•	impact of inflation and our ability to recover higher operating costs from our customers;


•	impact of interest rates on our stock price, cost of capital and ability to raise funds, expand operations or make future acquisitions;


•	impact of regulations on our compliance costs, the time to obtain required permits and throughput in our gathering systems;


•	acquisition of additional midstream assets from QEP and third parties;


•	impact of changes to the funding of affiliated and third party transactions on the comparability of our cash flow statements, working capital analysis and liquidity discussion;


•	changes in interest expense;


•	future cash distributions;


•	anticipated maintenance and expansion capital expenditures during fiscal 2013;


•	variance of expansion capital expenditures from period to period;


•	funding for acquisition and expansion capital expenditures;


•	maintenance of separate accounts and sources of liquidity and utilization of QEP's cash management system and expertise;


•	sources of liquidity;


•	sufficiency of cash generated from operations, borrowings under our revolving credit facility and issuance of additional debt and equity securities to satisfy short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions;


•	expected borrowing capacity under our Credit Facility;


•	exposure to credit risk resulting from the concentration of our customers;


•	impact of QEP's failure to perform under the terms of our gathering agreements or the Omnibus Agreement;


•	adequacy of our credit review procedures, loss reserves, customer deposits and collection procedures;


•	usefulness of historical data related only to properties conveyed to us in connection with the Offering;


•	planned agreements with QEP to sell condensate volumes;


•	supplemental disclosures regarding properties conveyed to us in the Offering; and


•	utilization of risk management tools to minimize future commodity price risks.

Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by third-party operators, processors and transporters;


•	the demand for oil and natural gas storage and transportation services;


•	our ability to successfully implement our business plan;


•	our ability to complete internal growth projects on time and on budget;


•	the price and availability of debt and equity financing;


•	the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


•	operating 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;


•	change in availability and cost of capital;


•	changes in tax status;


•	the effect of existing and future laws and government regulations;


•	the effects of future litigation; and


•	certain factors discussed elsewhere in this report and our Prospectus.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities law.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of June 30, 2013. Based on such evaluation, our management has concluded that, as of June 30, 2013, our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to our management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the

control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls

There were no changes in our internal controls over financial reporting during the quarter ended June 30, 2013, that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth under "Litigation" in Note 6 - Commitments and Contingencies to the Predecessor's unaudited consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

ITEM 1A. RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Company are set forth under "Risk Factors" in our Prospectus. No material changes to such risk factors have occurred during the three months ended June 30, 2013.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On April 19, 2013, in connection with the formation of the Partnership, the Partnership issued to (i) the General Partner, the 2.0% general partner interest in the partnership for $20, and (ii) to Field Services, the 98.0% limited partner interest in the partnership for $980. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), as they did not involve a public offering.

On August 8, 2013, our Registration Statement on Form S-1 (SEC Registration No 333-188487), as amended, (the "Registration Statement"), which we filed with the SEC relating to the Offering became effective. The Registration Statement registered 23,000,000 common units (including 3,000,000 over-allotment common units) with a maximum aggregate offering price of $483.0 million. Wells Fargo Securities, LLC, Morgan Stanley & Co. LLC, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., and J.P. Morgan Securities LLC, served as the joint book running managers for the Offering. Upon the closing of the Offering on August 14, 2013, we sold 20,000,000 common units representing limited partner interests in the Partnership at a price to the public of $21.00 per common unit. Net proceeds from the sale of the 20,000,000 common units were approximately $389.7 million, after deducting underwriting discounts and commissions of approximately $25.2 million and structuring fees and estimated offering expenses of approximately $5.1 million. We will use the net proceeds to (i) make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to us, (ii) repay our outstanding long-term debt balance, (iii) pay revolving credit facility origination fees and (iv) pay Wells Fargo Securities, LLC a structuring fee of $2.1 million.

At the closing of the Offering, we also issued (a) 1,090,000 unregistered general partner units and all our incentive distribution rights to the General Partner in exchange for its interest in the Operating Company, and (b) 6,701,750 unregistered common units and 26,705,000 unregistered subordinated units to Field Services as partial consideration for its interests in the Operating Company and a right to receive a distribution from the Partners. These transactions were exempt from registration under Section 4(2) of the Securities Act, as they did not involve a public offering.

On each of August 21, 2013, and September 4, 2013, we issued an additional 1,500,000 common units to the public following partial exercises by the underwriters of their over-allotment option to purchase additional common units. The net proceeds from the full exercise of the underwriters' option of $58.9 million, net of underwriters' discounts and structuring fees of $4.1 million, were used to redeem additional common units from Field Services.

The Gross aggregate offering amount of the common units sold pursuant to the Registration Statement was $483.0 million. From the effective date of the Registration Statement through September 4, 2013, we incurred underwriting discounts and commissions of $29.0 million and structuring fees and estimated offering expenses of approximately $5.4 million.

ISSUER PURCHASES OF EQUITY SECURITIES

The following table sets forth information with respect to repurchases by the Partnership of its common units during the period indicated.



Period	Total Number of Units Purchased⁽¹⁾	Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
August 1 through August 31, 2013	1,500,000	$	21.00	—	—
September 1 through September 30, 2013	1,500,000	$	21.00	—	—

⁽¹⁾ The Partnership redeemed 3,000,000 common units from Field Services with the net proceeds from the sale of 3,000,000 common units pursuant to the exercise of the underwriters' over-allotment option.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The following exhibits are being filed as part of this report:



Exhibit No.		Exhibits
3.1		First Amended and Restated Agreement of Limited Partnership of QEP Midstream Partners, LP, dated August 16, 2013, by and between QEP Midstream Partners GP, LLC and QEP Field Services Company, incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.1		QEP Midstream Partners, LP 2013 Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 13, 2013.
10.2		Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Phantom Unit Award Agreement, incorporated by reference to Exhibit 10.4 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013.
10.3		Form of QEP Midstream Partners, LP 2013 Long-Term Incentive Plan Director Unit Award Agreement, incorporated by reference to Exhibit 10.13 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 29, 2013.
10.4		Contribution, Conveyance and Assumption Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.5		Omnibus Agreement, dated as of August 14, 2013, by and among QEP Midstream Partners, LP, QEP Midstream Partners GP, LLC, QEP Resources, Inc., QEP Field Services Company and QEP Midstream Partners Operating, LLC, incorporated by reference to Exhibit 10.2 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.6		Credit Agreement, dated as of August 14, 2013, among QEP Midstream Partners Operating, LLC, as the borrower, QEP Midstream Partners, LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto, incorporated by reference to Exhibit 10.3 to the Partnership's Current Report on Form 8-K, filed with the Securities and Exchange Commission on August 16, 2013.
10.7		Gas Gathering Agreement, dated September 1, 1993, between Questar Gas Company (f/k/a Mountain Fuel Supply Company) and QEP Field Services Company (f/k/a Questar Pipeline Company), incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013, as amended by Amendment to the Gas Gathering Agreement, dated February 6, 1998, between Questar Gas Company and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.7 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 26, 2013.
10.8		Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company (f/k/a Questar Exploration and Production Company) and QEP Field Services Company (f/k/a Questar Gas Management Company), incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013, as amended by (i) First Amendment, dated March 1, 2006, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.9 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (ii) Second Amendment, dated August 16, 2007, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.10 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; (iii) Third Amendment, dated March 2, 2010, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.11 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013; and (iv) Fourth Amendment, dated July 1, 2011, to the Amended and Restated Gas Gathering Agreement, dated September 7, 2001, between QEP Energy Company and QEP Field Services Company, incorporated by reference to Exhibit 10.12 to the Partnership's Registration Statement on Form S-1/A, filed with the Securities and Exchange Commission on July 3, 2013. Certain portions of the Amended and Restated Gas Gathering Agreement, the First Amendment, the Third Amendment and the Fourth Amendment have been omitted pursuant to a confidential treatment request granted by the SEC.
31.1		Certification signed by C. B. Stanley, QEP Midstream Partners, LP's Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, QEP Midstream Partners, LP's Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.



32.1		Certification signed by C. B. Stanley and Richard J. Doleshek, QEP Midstream Partners, LP's Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.LAB		XBRL Label Linkbase Document
101.PRE		XBRL Presentation Linkbase Document
101.DEF		XBRL Definition Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		QEP MIDSTREAM PARTNERS, LP
		(Registrant)

	By:	QEP Midstream Partners GP, LLC
		(as General Partner)

September 19, 2013		/s/ Charles B. Stanley
		Charles B. Stanley,
		Chairman, President and Chief Executive Officer

September 19, 2013		/s/ Richard J. Doleshek
		Richard J. Doleshek,
		Executive Vice President,
		Chief Financial Officer and Treasurer

Attached files

QEP Midstream Partners, LP Reports

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