QEP Midstream Partners, LP - FORM 10-Q

Attached files

file	filename
EX-31.2 - EXHIBIT 31.2 - QEP Midstream Partners, LP	qepm-20140630xex312.htm
EX-31.1 - EXHIBIT 31.1 - QEP Midstream Partners, LP	qepm-20140630xex311.htm
EXCEL - IDEA: XBRL DOCUMENT - QEP Midstream Partners, LP	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - QEP Midstream Partners, LP	qepm-20140630xex321.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, 2014



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: 001-36047

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 800, 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 ý No o

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 26,719,037 common units, 26,705,000 subordinated units and 1,090,286 general partner units outstanding on July 31, 2014.

QEP Midstream Partners, LP

Form 10-Q for the Quarter Ended June 30, 2014

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			3

	ITEM 1.	FINANCIAL STATEMENTS	3

		UNAUDITED CONSOLIDATED STATEMENTS OF INCOME	3

		UNAUDITED CONSOLIDATED BALANCE SHEETS	4

		UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS	5

		UNAUDITED NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS	6

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	36

	ITEM 4.	CONTROLS AND PROCEDURES	38

PART II. OTHER INFORMATION			39

	ITEM 1.	LEGAL PROCEEDINGS	39

	ITEM 1A.	RISK FACTORS	39

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	39

	ITEM 4.	MINE SAFETY DISCLOSURES	39

	ITEM 5.	OTHER INFORMATION	39

	ITEM 6.	EXHIBITS	40

SIGNATURES			41

Explanatory Note

Certain information in this report includes periods prior to the completion of QEP Midstream Partners, LP's initial public offering (IPO) and prior to the effective dates of the agreements related to the IPO that are discussed herein. Consequently, the unaudited consolidated financial statements and related discussion of financial condition and results of operations contained in this report include periods that pertain to QEP Midstream Partners, LP Predecessor, our predecessor for accounting purposes. Because the results of our predecessor include results for both the properties conveyed to us in connection with 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 the IPO on August 14, 2013), refer to QEP Midstream Partners, LP Predecessor. References in this report to "QEP Midstream" the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after the IPO, in the present tense or prospectively (starting August 14, 2013), refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of this report, “QEP” refers to QEP Resources, Inc. and its consolidated subsidiaries including the Partnership.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	Successor			Predecessor			Successor			Predecessor
	(in millions, except per unit amounts)
Revenues
Gathering and transportation	$	28.4		$	37.1		$	57.3		$	73.7
Condensate sales	1.8			3.0			3.9			6.5
Total revenues	30.2			40.1			61.2			80.2
Operating expenses
Gathering expense	5.4			8.3			11.8			16.0
General and administrative	5.2			4.7			9.9			10.4
Taxes other than income taxes	0.5			0.6			1.0			0.9
Depreciation and amortization	8.2			9.8			16.0			20.1
Total operating expenses	19.3			23.4			38.7			47.4
Net loss from property sales	—			(0.1		)	—			(0.4		)
Operating income	10.9			16.6			22.5			32.4
Income from unconsolidated affiliates	0.4			2.1			1.9			3.4
Interest expense	(0.5		)	(1.0		)	(1.1		)	(2.1		)
Net income	10.8			17.7			23.3			33.7
Net income attributable to noncontrolling interest	(0.9		)	(1.3		)	(1.7		)	(1.9		)
Net income attributable to QEP Midstream or Predecessor	$	9.9		$	16.4		$	21.6		$	31.8

Net income attributable to QEP Midstream per limited partner unit (basic and diluted):
Common units	$	0.18					$	0.39
Subordinated units	$	0.18					$	0.39

Weighted-average limited partner units outstanding (basic and diluted):
Common units	26.7						26.7
Subordinated units	26.7						26.7

See notes accompanying the unaudited consolidated financial statements.

QEP MIDSTREAM PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2014		December 31, 2013
	Successor		Successor
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	16.5	$	19.0
Accounts receivable, net	11.7		9.1
Accounts receivable from related party	33.0		25.5
Natural gas imbalance receivable	13.2		1.7
Total current assets	74.4		55.3
Property, plant and equipment, net	486.2		493.4
Investment in unconsolidated affiliates	25.7		27.8
Other noncurrent assets	3.0		3.4
Total assets	$	589.3	$	579.9
LIABILITIES
Current liabilities:
Accounts payable	$	7.2	$	6.6
Accounts payable to related party	9.1		9.0
Natural gas imbalance liability	13.2		1.7
Deferred revenue	12.9		9.6
Other current liabilities	1.0		0.2
Total current liabilities	43.4		27.1
Asset retirement obligation	13.8		13.3
Deferred revenue	11.7		11.9
Total long-term liabilities	25.5		25.2
Commitments and contingencies (see Note 9)
EQUITY
Limited partner common units - 26.7 million units issued and outstanding	408.7		411.7
Limited partner subordinated units - 26.7 million units issued and outstanding	65.3		68.0
General partner units - 1.1 million units issued and outstanding	2.3		2.5
Total partners' capital	476.3		482.2
Noncontrolling interest	44.1		45.4
Total equity	520.4		527.6
Total liabilities and equity	$	589.3	$	579.9

See notes accompanying the unaudited consolidated financial statements.

QEP MIDSTREAM PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2014			2013
	Successor			Predecessor
OPERATING ACTIVITIES	(in millions)

Net income	$	23.3		$	33.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	16.0			20.1
Equity-based compensation expense	0.6			—
Income from unconsolidated affiliates	(1.9		)	(3.4		)
Distributions from unconsolidated affiliates	4.2			4.1
Amortization of debt issuance costs	0.3			—
Net loss from asset sales	—			0.4
Changes in operating assets and liabilities:
Accounts receivable	(10.1		)	7.7
Accounts payable and accrued expenses	3.8			4.4
Other	3.7			(3.6		)
Net cash provided by operating activities	39.9			63.4
INVESTING ACTIVITIES
Property, plant and equipment	(11.4		)	(7.5		)
Proceeds from sale of assets	—			0.9
Net cash used in investing activities	(11.4		)	(6.6		)
FINANCING ACTIVITIES
Repayments of long-term debt (to related party)	—			(43.7		)
Contributions from (distributions to) parent, net	1.0			(8.3		)
Distributions to unitholders	(28.9		)	—
Distribution to noncontrolling interest	(3.1		)	(3.1		)
Net cash used in financing activities	(31.0		)	(55.1		)
Change in cash and cash equivalents	(2.5		)	1.7
Beginning cash and cash equivalents	19.0			1.4
Ending cash and cash equivalents	$	16.5		$	3.1

Supplemental Disclosures:
Non-cash investing activities
Change in capital expenditure accrual balance	$	(3.1	)	$	(2.3	)

See notes accompanying the unaudited consolidated financial statements.

QEP MIDSTREAM PARTNERS, LP

NOTES ACCOMPANYING THE CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Nature of Business

QEP Midstream Partners, LP (the Partnership) was formed in Delaware on April 19, 2013, to own, operate, acquire and develop midstream energy assets. The Partnership's assets consist of ownership interests in four gathering systems and two 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.

On August 14, 2013, the Partnership completed its initial public offering (the IPO) of common units representing limited partner interests in the Partnership (see Note 3 - Initial Public Offering). Unless the context otherwise requires, references in this report to "Predecessor," "we," "our," "us," or like terms, when used on a historical basis (periods prior to the IPO), refer to QEP Midstream Partners, LP Predecessor (the Predecessor). References in this report to "QEP Midstream" the "Partnership," "Successor," "we," "our," "us," or like terms, when used from and after the IPO, 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, including the Partnership.

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

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

Note 2 - Basis of Presentation of Interim Consolidated Financial Statements

Basis of Presentation

The interim unaudited consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States (GAAP) and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

Interim consolidated financial statements are unaudited and do not include all of the information and notes required by GAAP for audited consolidated financial statements. These financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2013, included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013, 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 results of operations and financial position. Amounts reported in the Unaudited Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods.

The unaudited consolidated financial statements and accompanying notes prior to the IPO relate to the Predecessor and have been prepared in accordance with GAAP on the basis of QEP's historical ownership of the Predecessor assets. The Predecessor's consolidated financial statements have been prepared from the separate records maintained by QEP and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Further, management does not believe that these financial statements are necessarily comparable to the financial statements reported by the Partnership for periods subsequent to the IPO nor reflective of other transactions that resulted in the capitalization and start-up of the Partnership. 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 IPO.

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Partnership is currently assessing the impact on the Partnership's consolidated financial statements.

Note 3 - Initial Public Offering

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

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

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



Total proceeds from the IPO	$	483.0
Offering costs	(33.4		)
Net proceeds from the IPO	449.6
Revolving credit facility origination fees	(3.0		)
Repayment of outstanding debt with QEP	(95.5		)
Net proceeds distributed to QEP from the IPO	$	351.1

As of June 30, 2014, the Partnership's ownership consisted of the following:



	Units	% Ownership
Limited partner common units - QEP	3,701,750	6.8	%
Limited partner common units - public	23,017,287	42.2	%
Limited partner subordinated units - QEP	26,705,000	49.0	%
General partner units	1,090,286	2.0	%
Total QEP Midstream units	54,514,323	100.0	%

Contribution, Conveyance and Assumption Agreement and Concurrent Transactions

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


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


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


•	QEP Field Services contributed to the Partnership, as a capital contribution, its remaining limited liability company interests in the Operating Company in exchange for (a) 6,701,750 common units representing a 12.3% limited partner

interest in the Partnership, (b) 26,705,000 subordinated units representing a 49% limited partner interest in the Partnership and (c) the right to receive a distribution from the Partnership;


•	the public, through the underwriters, contributed $420.0 million in cash (or $390.7 million, net of the underwriters' discounts and commissions, structuring fees and offering expenses of approximately $29.3 million) to the Partnership in exchange for the issuance of 20,000,000 common units; and


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

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



Cash and cash equivalents	$	1.1
Accounts receivable, net	26.4
Property, plant and equipment, net	485.6
Investment in unconsolidated affiliate	27.9
Account payable and accrued expenses	(21.1		)
Long-term debt to related party	(95.5		)
Asset retirement obligation	(11.8		)
Other liabilities	(4.8		)
Net assets	$	407.8

Note 4 - Related Party Transactions

The following table summarizes the related party income statement transactions of the Partnership and Predecessor with QEP:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	Successor			Predecessor			Successor			Predecessor
	(in millions)
Revenues from affiliate	$	20.8		$	20.6		$	42.5		$	41.3
General and administrative to affiliate	(3.4		)	(4.7		)	(6.9		)	(10.4		)
Interest expense to affiliate	—			(1.0		)	—			(2.1		)

The Partnership

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of June 30, 2014, QEP Field Services owns 3,701,750 common units and 26,705,000 subordinated units representing a 55.8% limited partner interest in us. In addition, the General Partner owns 1,090,286 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEP Field Services and QEP are considered to be related party transactions, because our General Partner and its affiliates own more than 5% of our equity interests. In addition to the agreements discussed in Note 3 - Initial Public Offering, the Partnership entered into the following agreements with QEP.

Omnibus Agreement

In connection with the IPO, the Partnership entered into an Omnibus Agreement (the Omnibus Agreement) with QEP Field Services, the General Partner, the Operating Company and QEP, which addresses the following matters:

•

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


•	the Partnership's obligation to reimburse QEP for any out-of-pocket costs and expenses incurred by QEP in providing general and administrative services (which reimbursement is in addition to certain expenses of the General Partner and

its affiliates that are reimbursed under the Partnership's partnership agreement), as well as any other out-of-pocket expenses incurred by QEP on the Partnership's behalf; and


•	an indemnity by QEP for certain environmental and other liabilities, and the Partnership's obligation to indemnify QEP and its subsidiaries for events and conditions associated with the operation of the Partnership's assets that occur after the closing of the IPO.

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

For the three and six months ended June 30, 2014, the Partnership was charged $3.4 million and $6.9 million, respectively, under the Omnibus Agreement by QEP.

Service Agreements

In connection with the IPO, the Partnership entered into various midstream agreements with QEP including, but not limited to, natural gas, crude oil, water and condensate gathering and transportation agreements, a fixed-price condensate purchase agreement, operating agreements and other service agreements. The Partnership believes that the terms and conditions under these agreements are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services in the ordinary course of its business.

The Predecessor

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

Centralized Cash Management

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

Affiliated Debt

The Predecessor's long-term debt consisted of an allocation from QEP Field Services of its total long-term debt related to QEP Field Services' debt agreements with QEP. During 2013, QEP Field Services had a $250.0 million promissory note with QEP, which matured at the end of the first quarter of 2013 with a fixed interest rate of 6.05%. The promissory note was renewed on April 1, 2013, and matured on April 1, 2014. In addition, QEP Field Services entered into a $1.0 billion revolving credit type promissory note with QEP, with a maturity date of April 1, 2017, to assist with funding of capital expenditures. Interest allocated to the Predecessor under these notes in the first quarter of 2013 was based on the fixed-rate due to QEP and was settled in cash. QEP Field Services was in compliance with its covenants under the agreements for all periods prior to the IPO, and there were no letters of credit outstanding. In connection with the IPO, $95.5 million of affiliated debt was assumed by the Partnership and was repaid in full on August 14, 2013, with proceeds of the IPO extinguishing all affiliated debt of the Partnership.

Allocation of Costs

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

Note 5 - Property, Plant and Equipment

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



	Estimated Useful Lives	June 30, 2014			December 31, 2013
		Successor			Successor
		(in millions)
Gathering equipment	5 to 40 years	$	746.1		$	737.9
Accumulated depreciation		(259.9		)	(244.5		)
Total net property, plant and equipment		$	486.2		$	493.4

Note 6 - Asset Retirement Obligations

The Partnership 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 (in millions):



	Asset Retirement Obligations
ARO liability at January 1, 2014	$	13.3
Accretion	0.4
Liabilities incurred	0.1
ARO liability at June 30, 2014	$	13.8

Note 7 - Debt

In connection with the IPO, we entered into a $500.0 million senior secured revolving credit facility (the Credit Facility) with a group of financial institutions. The Credit Facility matures on August 14, 2018, and contains an accordion provision that would allow for the amount of the facility to be increased to $750.0 million with the agreement of the lenders. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for transactions of this nature.

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


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


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

As of June 30, 2014, there was no debt outstanding under the Credit Facility, and the Partnership was in compliance with the covenants under the credit agreement. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.325% to 0.500% per annum depending on the Partnership's consolidated leverage ratio (as defined in the Credit Facility agreement). For the three and six months ended June 30, 2014, the Partnership incurred $0.4 million and $0.8 million of commitment fees, respectively. All debt outstanding prior to and at the IPO relates to intercompany debt with QEP discussed in Note 4 - Related Party Transactions. The net proceeds from the IPO were used to pay off the $95.5 million of debt assumed by the Partnership in connection with the IPO.

Note 8 - Equity-Based Compensation

In connection with the IPO, the board 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 equity-based awards. The LTIP limits the number of common units that may be delivered pursuant to awards under the LTIP to 5,341,000 common units. Common units cancelled or forfeited will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a designated committee thereof.

Common Units

During the six months ended June 30, 2014, the Board granted 8,289 common units to the non-employee directors of the Board at $23.53 per unit, which vested immediately. The fair value of common unit awards granted to non-employee directors is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized at the time of grant, because the common unit awards vest immediately and are non-forfeitable.

Phantom Units

During the six months ended June 30, 2014, the Board granted 13,439 phantom units to employees of the General Partner, which vest in equal installments over a three-year period from the grant date and are payable in common units. The fair value of phantom unit awards granted to employees is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized over the vesting period of three years.

The following is a summary of the Partnership's phantom unit award activity for the period ended June 30, 2014:



	Phantom Units Outstanding	Weighted-Average Grant-Date Fair Value Per Unit
Unvested balance at beginning of the period	38,250	$	22.03
Granted	13,439	23.68
Unvested balance at June 30, 2014	51,689	$	22.46

Total compensation expense recognized for the common unit and phantom unit awards for the three and six months ended June 30, 2014, was $0.2 million and $0.6 million, respectively, and the total amount of unrecognized compensation cost related to the phantom unit award was $0.6 million as of June 30, 2014, which is expected to be recognized over the remaining vesting period of 2.3 years.

Note 9 - Commitments and Contingencies

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

Litigation

At the closing of the IPO, the assets and agreement subject to the ongoing litigation between Questar Gas Company (QGC) and QEP Field Services, styled Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah, were assigned to the Partnership. QEP Field Services' former affiliate, QGC, filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Under the 1993 Agreement, certain of our systems provide gathering services to QGC charging an annual gathering rate which is based on the 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 netted the disputed amount from its monthly payment of the gathering fees to QEP Field Services and has continued to net such amount from its monthly payment to the Partnership. As of June 30, 2014, the Partnership has deferred revenue of $11.6 million related to the QGC disputed amount. Specific monetary damages are not asserted. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement. QGC may seek to amend its complaint to add the Partnership as a defendant in the litigation. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement (defined above in Note 4 - Related Party Transactions).

Note 10 - Net Income Per Limited Partner Unit

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

Net income per unit is only calculated for the period subsequent to the IPO as no units were outstanding prior to August 14, 2013. As of June 30, 2014, the basic net income per unit and the diluted net income per unit were equal as there were no potentially dilutive units outstanding.

The following tables set forth distributions in excess of net income attributable to QEP Midstream and the calculation of net income per unit for the three and six months ended June 30, 2014.



	Three Months Ended June 30, 2014			Six Months Ended June 30, 2014
	(in millions)

Net income attributable to QEP Midstream	$	9.9		$	21.6
General partner's distribution declared⁽¹⁾	(0.3		)	(0.6		)
Limited partners' distribution declared on common units⁽¹⁾	(7.5		)	(14.7		)
Limited partners' distribution declared on subordinated units⁽¹⁾	(7.5		)	(14.7		)
Distribution in excess of net income attributable to QEP Midstream	$	(5.4	)	$	(8.4	)

⁽¹⁾ On July 22, 2014, the Partnership declared its quarterly cash distribution totaling $15.3 million, or $0.28 per unit for the second quarter of 2014. The quarterly distribution will be paid on August 14, 2014, to unitholders of record as of the close of business on August 4, 2014. During the three and six months ended June 30, 2014, no net income was attributable to incentive distribution rights.



	Three Months Ended June 30, 2014
	General Partner			Limited Partners' Common Units			Limited Partners' Subordinated Units			Total
	(in millions, except per unit amounts)
Net income attributable to QEP Midstream:
Distribution declared	$	0.3		$	7.5		$	7.5		$	15.3
Distributions in excess of net income attributable to QEP Midstream	(0.2		)	(2.6		)	(2.6		)	(5.4		)
Net income attributable to QEP Midstream	$	0.1		$	4.9		$	4.9		$	9.9

Weighted-average units outstanding
Basic and diluted	1.1			26.7			26.7			54.5
Net income per limited partner unit attributable to the QEP Midstream
Basic and diluted				$	0.18		$	0.18



	Six Months Ended June 30, 2014
	General Partner			Limited Partners' Common Units			Limited Partners' Subordinated Units			Total
	(in millions, except per unit amounts)
Net income attributable to QEP Midstream:
Distribution declared	$	0.6		$	14.7		$	14.7		$	30.0
Distributions in excess of net income attributable to QEP Midstream	(0.2		)	(4.1		)	(4.1		)	(8.4		)
Net income attributable to QEP Midstream	$	0.4		$	10.6		$	10.6		$	21.6

Weighted-average units outstanding
Basic and diluted	1.1			26.7			26.7			54.5
Net income per limited partner unit attributable to the QEP Midstream
Basic and diluted				$	0.39		$	0.39

Note 11 - Subsequent Events

Distribution

On July 22, 2014, the Partnership declared a quarterly cash distribution totaling $15.3 million, or $0.28 per unit for the second quarter of 2014. The quarterly distribution will be paid on August 14, 2014, to unitholders of record as of the close of business on August 4, 2014.

Acquisition

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, LLC (Green River Processing), a wholly owned subsidiary of QEP Field Services, from QEP Field Services for $230.0 million (the Green River Processing Acquisition). The Green River Processing Acquisition was funded with $220.0 million of borrowings under the Credit Facility and cash on hand. The Green River Processing Acquisition will be accounted for as an equity investment in unconsolidated affiliate. The investment will be recorded at the carrying value as of the acquisition date as the Green River Processing Acquisition represents a transaction between entities under common control with the difference between the carrying amount and the purchase price recorded to equity.

Green River Processing owns the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming. The aggregate processing capacity of Green River Processing is up to 890 MMcf per day, comprised of up to 560 MMcf per day of cryogenic processing capacity and 330 MMcf per day of Joule-Thomson processing capacity. In addition, there is 15,000 barrels per day of NGL fractionation capacity at the Blacks Fork processing complex.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited historical consolidated financial statements and notes in Item 1. Financial Statements contained herein and the Partnership's audited consolidated financial statements for the year ended December 31, 2013, included in our Annual Report on Form 10-K. Among other things, those historical consolidated 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 within 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 Annual Report on Form 10-K. See also Forward-Looking Statements in Item 3 of this report. For a glossary of commonly used terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Terms" provided in the Partnership's 2013 Annual Report on Form 10-K.

Overview

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

On August 14, 2013, the Partnership's common units began trading on the NYSE after the completion of the IPO of 20,000,000 common units at a price to the public of $21.00 per common unit. Following the IPO, the underwriters exercised their over-allotment option to purchase an additional 3,000,000 common units, at a price of $21.00 per common unit. The Partnership received net proceeds of $449.6 million from the sale of the common units, after deducting underwriting discounts and commissions, structuring fees and offering expenses totaling approximately $33.4 million. The Partnership used the net proceeds to repay its outstanding debt balance to QEP, which was assumed with the assets contributed to the Partnership, pay revolving credit facility origination fees and make a cash distribution to QEP, a portion of which was used to reimburse QEP for certain capital expenditures it incurred with respect to assets contributed to the Partnership.

The Partnership's assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the 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 373 miles of natural gas gathering pipelines, 56 miles of crude oil gathering pipelines, 88 miles of water gathering pipelines and a 61-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have a total natural gas throughput capacity of 737 MMcf/d, total crude oil and condensate throughput capacity of 7,137 Bbls/d, total water throughput capacity of 21,990 Bbls/d, and a total of 40,800 Bbls/d of throughput capacity on our FERC-regulated pipeline.

◦

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


◦	Rendezvous Pipeline. Rendezvous Pipeline's sole asset is a 21-mile, FERC-regulated natural gas transmission pipeline that provides gas transportation services from QEP Field Services' Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. Rendezvous Pipeline has total throughput capacity of 450 MMcf/d.


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

•

Three Rivers Gathering System. Three Rivers Gathering is a joint venture between QEP Midstream and Ute Energy Midstream Holdings, LLC that was formed to transport natural gas from the Uinta Basin area to a processing facility owned by QEP Field Services and third parties. The Three Rivers Gathering System consists of gas gathering assets located in the Uinta Basin in northeast Utah, including approximately 52 miles of gathering pipeline and 4,735 bhp of gas compression. The Three Rivers Gathering System has total throughput capacity of 212 MMcf/d. We own a 50% interest in Three Rivers Gathering.

•

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

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

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

Recent Developments

In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate QEP’s midstream business, including the ownership and control of QEP Field Services, which include its general and limited partner interests in QEP Midstream. In June 2014, QEP Field Services filed a Registration Statement on Form 10 with the Securities and Exchange Commission (SEC) in connection with the separation of QEP’s midstream business into a separate publicly traded company. We believe there is nothing in QEP’s announced strategy and recent activity related to separating its midstream business that precludes QEP Field Services from offering us acquisition opportunities to purchase additional midstream assets from it or from jointly pursuing midstream acquisitions with us prior to or subsequent to the separation. Further, we do not believe QEP’s acreage dedicated to our assets will be changed significantly due to the separation, and we believe these acreage dedications will continue to provide us a platform for future organic growth from our existing assets.

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, LLC (Green River Processing) from QEP Field Services for $230.0 million, subject to customary purchase price adjustments, (the Green River Processing Acquisition). The Green River Processing Acquisition was funded by the Partnership with $220.0 million of borrowings under the Credit Facility and cash on hand.

Our Operations

Our results are driven primarily by the volumes of oil and natural gas we gather and the fees we charge 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. For the three and six months ended June 30, 2014, approximately 6% of our Partnership's revenue was generated through the sale of condensate volumes that we collected on our gathering systems. Although the Partnership has entered into a fixed price condensate sales agreement with QEP, we still have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of

oil and natural gas available for gathering by our systems. Refer to Item 3 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, in the aggregate, maintain or increase our existing throughput levels and offset the natural production declines of the wells currently connected to our gathering systems. Specifically, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and are located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering contract and located within the dedicated acreage in which our gathering systems currently exist or could be expanded to connect to additional wells.

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

How We Evaluate Our Business

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

Throughput volumes

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

Gathering expenses

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

Maintenance and Expansion Capital Expenditures

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

Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

We define Adjusted EBITDA as net income attributable to the Partnership or the Predecessor before depreciation and amortization, interest and other income and expense, gains and losses from asset sales, deferred revenue associated with minimum volume commitment payments and certain other non-cash and/or non-recurring items. We define Distributable Cash Flow as Adjusted EBITDA less net cash interest paid, maintenance capital expenditures and cash adjustments related to equity

method investments and non-controlling interests, and other non-cash expenses. Distributable Cash Flow does not reflect changes in working capital balances.

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by management and by external users of our financial statements, such as investors and commercial banks, to assess:


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


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


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


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

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

General Trends and Outlook

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

Oil and natural gas supply and demand

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

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 relatively low 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 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 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 establishes pipeline integrity management programs that could 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 may increase the time that it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems.

Acquisition opportunities

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

Factors Affecting the Comparability of Our Financial Results

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

Assets not included in the Partnership

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

General and administrative expenses

General and administrative expenses were allocated to the Predecessor based on its proportionate share of QEP's gross property, plant and equipment, operating income and direct labor costs. Management believes these allocation methodologies were reasonable. In connection with the IPO, the Partnership entered into the Omnibus Agreement which establishes the general and administrative expense that QEP will charge the Partnership. The Predecessor's general and administrative expenses included costs allocated by QEP. These costs were reimbursed and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources, and (iii) compensation, share-based compensation, benefits and pension and post-retirement costs. For the three and six months ended June 30, 2013, the Predecessor incurred $4.7 million and $10.4 million, respectively, in general and administrative expenses.

In accordance with the Omnibus Agreement, QEP charges the Partnership a combination of direct and allocated charges for administrative and operational services. The annual fee is currently set at $13.8 million. For the three and six months ended June 30, 2014, the Partnership incurred $3.4 million and $6.9 million, respectively, of such administrative and operational services expenses.

In addition to the charges under the Omnibus Agreement, we anticipate incurring approximately $2.5 million per year 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 consolidated financial statements prior to the IPO. The Partnership's general and administrative expense also includes compensation expense associated with the LTIP, which was implemented in connection with the IPO. For the three and six months ended June 30, 2014, the Partnership

incurred $1.8 million and $3.0 million, respectively, of incremental general and administrative expenses, which includes $1.1 million of transaction costs incurred related to the Green River Processing Acquisition.

Working capital

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

Interest expense

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

Cash distributions to unitholders

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

Results of Operations

The discussion of our historical performance and financial condition is presented for the Partnership (Successor), for the three and six months ended June 30, 2014, and for the Predecessor for the three and six months ended June 30, 2013.

As previously discussed, the historical financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes results for both the properties conveyed to the Partnership in connection with the IPO and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the IPO, adjusted for transactions that occurred as a result of the IPO, is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations. Therefore, we have also included the results of operations for the three and six months ended June 30, 2013, on a pro forma basis.

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

Refer to "Factors Affecting the Comparability of Our Financial Results" above for a description of the significant factors affecting the comparability of the Predecessor's historical results of operations and those of the Partnership subsequent to the IPO.



	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
	Successor			Predecessor As Reported			Pro Forma Adjustments ⁽¹⁾				Pro Forma
	(in millions, except operating and per unit amounts)
Revenues
Gathering and transportation	$	28.4		$	37.1		$	(8.4	)		$	28.7
Condensate sales	1.8			3.0			(0.4		)		2.6
Total revenues	30.2			40.1			(8.8		)		31.3
Operating expenses
Gathering expense	5.4			8.3			(2.5		)		5.8
General and administrative	5.2			4.7			(0.6		)	⁽²⁾	4.1
Taxes other than income taxes	0.5			0.6			(0.3		)		0.3
Depreciation and amortization	8.2			9.8			(2.5		)		7.3
Total operating expenses	19.3			23.4			(5.9		)		17.5
Net loss from property sales	—			(0.1		)	0.1				—
Operating income	10.9			16.6			(2.8		)		13.8
Income from unconsolidated affiliates	0.4			2.1			(1.2		)		0.9
Interest expense	(0.5		)	(1.0		)	0.5			⁽³⁾	(0.5		)
Net income	10.8			17.7			(3.5		)		14.2
Net income attributable to noncontrolling interest	(0.9		)	(1.3		)	—				(1.3		)
Net income attributable to QEP Midstream or Predecessor	$	9.9		$	16.4		$	(3.5	)		$	12.9
Operating Statistics
Natural gas throughput in millions of MMBtu
Gathering and transportation	75.8			94.4			(18.8		)		75.6
Equity interest ⁽⁴⁾	5.4			7.3			(0.5		)		6.8
Total natural gas throughput	81.2			101.7			(19.3		)		82.4
Throughput attributable to noncontrolling interests⁽⁵⁾	(2.7		)	(2.7		)	—				(2.7		)
Total throughput attributable to QEP Midstream or Predecessor	78.5			99.0			(19.3		)		79.7
Crude oil and condensate gathering system throughput volumes (in MBbls)	1,112.0			1,380.8			—				1,380.8
Water gathering volumes (in MBbls)	1,174.3			1,027.6			—				1,027.6
Condensate sales volumes (in MBbls)	20.9			36.2			(3.3		)		32.9
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.31		$	0.34						$	0.32
Average oil and condensate gathering fee (per barrel)	$	2.39		$	2.14						$	2.14
Average water gathering fee (per barrel)	$	1.87		$	1.83						$	1.83
Average condensate sale price (per barrel)	$	85.25		$	80.96						$	80.94
Non-GAAP Measures
Adjusted EBITDA ⁽⁶⁾	$	18.0		$	27.0		$	(6.6	)		$	20.4
Distributable Cash Flow ⁽⁶⁾	$	15.9


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


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

⁽³⁾

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


⁽⁴⁾	Includes our 50% share of gross volumes from Three Rivers Gathering and the Predecessor's 38% share of gross volumes from Uintah Basin Field Services.


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


⁽⁶⁾	Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “Supplemental Pro Forma Analysis —Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)” below for definitions of these non-GAAP financial measures and reconciliations to the most directly comparable GAAP financial measures.



	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
	Successor			Predecessor As Reported			Pro Forma Adjustments ⁽¹⁾				Pro Forma
	(in millions, except operating and per unit amounts)
Revenues
Gathering and transportation	$	57.3		$	73.7		$	(16.0	)		$	57.7
Condensate sales	3.9			6.5			(1.9		)		4.6
Total revenues	61.2			80.2			(17.9		)		62.3
Operating expenses
Gathering expense	11.8			16.0			(4.4		)		11.6
General and administrative	9.9			10.4			(1.8		)	⁽²⁾	8.6
Taxes other than income taxes	1.0			0.9			(0.4		)		0.5
Depreciation and amortization	16.0			20.1			(5.1		)		15.0
Total operating expenses	38.7			47.4			(11.7		)		35.7
Net loss from property sales	—			(0.4		)	0.4				—
Operating income	22.5			32.4			(5.8		)		26.6
Income from unconsolidated affiliates	1.9			3.4			(1.9		)		1.5
Interest expense	(1.1		)	(2.1		)	1.0			⁽³⁾	(1.1		)
Net income	23.3			33.7			(6.7		)		27.0
Net income attributable to noncontrolling interest	(1.7		)	(1.9		)	—				(1.9		)
Net income attributable to QEP Midstream or Predecessor	$	21.6		$	31.8		$	(6.7	)		$	25.1
Operating Statistics
Natural gas throughput in millions of MMBtu
Gathering and transportation	145.6			185.0			(36.9		)		148.1
Equity interest ⁽⁴⁾	10.6			10.6			(0.9		)		9.7
Total natural gas throughput	156.2			195.6			(37.8		)		157.8
Throughput attributable to noncontrolling interests⁽⁵⁾	(5.3		)	(5.3		)	—				(5.3		)
Total throughput attributable to QEP Midstream or Predecessor	150.9			190.3			(37.8		)		152.5
Crude oil and condensate gathering system throughput volumes (in MBbls)	2,182.1			2,659.6			—				2,659.6
Water gathering volumes (in MBbls)	2,250.1			1,897.7			—				1,897.7
Condensate sales volumes (in MBbls)	45.9			78.9			(22.7		)		56.2
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.31		$	0.34						$	0.32
Average oil and condensate gathering fee (per barrel)	$	2.37		$	2.08						$	2.08
Average water gathering fee (per barrel)	$	1.86		$	1.82						$	1.82
Average condensate sale price (per barrel)	$	85.25		$	82.05						$	82.68
Non-GAAP Measures
Adjusted EBITDA ⁽⁶⁾	$	37.4		$	53.4		$	(13.2	)		$	40.2
Distributable Cash Flow ⁽⁶⁾	$	33.3


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


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

⁽³⁾


⁽⁴⁾	Includes our 50% share of gross volumes from Three Rivers Gathering and the Predecessor's 38% share of gross volumes from Uintah Basin Field Services.


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


⁽⁶⁾	Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “Supplemental Pro Forma Analysis —Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)” below for definitions of these non-GAAP financial measures and reconciliations to the most directly comparable GAAP financial measures.

Successor Results of Operations

On August 14, 2013, the Partnership completed its IPO. Prior to the IPO, QEP Field Services and the General Partner contributed, as capital contributions, $407.8 million of net assets representing their limited liability company interest in the Operating Company. The contribution of QEP Field Services’ and the General Partners’ limited liability interest in the Operating Company to the Partnership was valued using the carryover book value of the Operating Company, as the transaction is a transfer of assets between entities under common control. The assets of the Partnership contributed by QEP consist of ownership interests in four gathering systems and two FERC-regulated pipelines and exclude the Uinta Basin Gathering System and general support equipment, which were retained by QEP Field Services. The Partnership’s (Successor’s) operating results for the three and six months ended June 30, 2014, are presented below.

Three Months Ended June 30, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $28.4 million for three months ended June 30, 2014.

Natural gas gathering and transportation revenue was $23.6 million with throughput of 75.8 MMBtu and an average gas gathering and transportation fee of $0.31 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 52.6 MMBtu of throughput, and our Vermillion Gathering System, which contributed throughput of 10.6 MMBtu.

Crude oil and condensate gathering revenue was $2.6 million for the three months ended June 30, 2014. The average gathering fee was $2.39 per barrel and throughput was 1,112.0 MBbls of which 853.8 MBbls was attributable to our Green River Gathering System and 258.2 MBbls was attributable to our Williston Gathering System.

Water gathering revenue was $2.2 million for the three months ended June 30, 2014, with throughput of 1,174.3 MBbls and an average fee of $1.87 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $1.8 million for the three months ended June 30, 2014. Sales volumes were 20.9 MBbls at a fixed price of $85.25 per barrel pursuant to our fixed price sales agreement with QEP.

Operating Expenses

Gathering expense. Gathering expense was $5.4 million for the three months ended June 30, 2014, the majority of which was incurred on our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $5.2 million for the three months ended June 30, 2014, consisting of $3.4 million of charges under the Omnibus Agreement, $0.2 million of equity-based compensation expense, $1.1 million of professional services fees incurred for the Green River Processing Acquisition, and $0.5 million of expenses related to operating as a publicly traded partnership, including fees for external audit procedures.

Taxes other than income taxes. Taxes other than income taxes were $0.5 million for the three months ended June 30, 2014, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $8.2 million for the three months ended June 30, 2014.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $0.4 million for the three months ended June 30, 2014, related to income from our ownership interest in Three Rivers Gathering.

Interest expense. Interest expense was $0.5 million for the three months ended June 30, 2014, which consisted of $0.4 million related to commitment fees paid on the unused portion of the Credit Facility and $0.1 million related to the amortization of debt issuance costs. There were no borrowings under the Credit Facility during the period.

Six Months Ended June 30, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $57.3 million for the six months ended June 30, 2014.

Natural gas gathering and transportation revenue was $45.1 million with throughput of 145.6 MMBtu and an average gas gathering and transportation fee of $0.31 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 99.5 MMBtu of throughput, and our Vermillion Gathering System, which contributed throughput of 21.6 MMBtu.

Crude oil and condensate gathering revenue was $5.1 million for the six months ended June 30, 2014. The average gathering fee was $2.37 per barrel and throughput was 2,182.1 MBbls of which 1,654.2 MBbls was attributable to our Green River Gathering System and 527.9 MBbls was attributable to our Williston Gathering System.

Water gathering revenue was $4.2 million for the six months ended June 30, 2014, with throughput of 2,250.1 MBbls and an average fee of $1.86 per barrel at our Green River Gathering System.

The remaining portion of gathering and transportation revenue for the six months ended June 30, 2014, related to deficiency revenue of $2.9 million, all of which was attributable to our Williston Gathering System.

Condensate sales. Revenue from condensate sales was $3.9 million for the six months ended June 30, 2014. Sales volumes were 45.9 MBbls at a fixed price of $85.25 per barrel pursuant to our fixed price sales agreement with QEP.

Operating Expenses

Gathering expense. Gathering expense was $11.8 million for the six months ended June 30, 2014, the majority of which was incurred on our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $9.9 million for the six months ended June 30, 2014, consisting of $6.9 million of charges under the Omnibus Agreement, $0.6 million of equity-based compensation expense, $1.1 million of professional services fees incurred for the Green River Processing Acquisition, and $1.3 million of expenses related to operating as a publicly traded partnership.

Taxes other than income taxes. Taxes other than income taxes were $1.0 million for the six months ended June 30, 2014, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $16.0 million for the six months ended June 30, 2014.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $1.9 million for the six months ended June 30, 2014, related to income from our ownership interest in Three Rivers Gathering.

Interest expense. Interest expense was $1.1 million for the six months ended June 30, 2014, which consisted of $0.8 million related to commitment fees paid on the unused portion of the Credit Facility and $0.3 million related to the amortization of debt issuance costs. There were no borrowings under the Credit Facility during the period.

Predecessor Results of Operations

The Predecessor financial statements were prepared in connection with the IPO. The Predecessor consisted of all of the Partnership’s gathering assets as well as the Uinta Basin Gathering System and general support equipment. The Uinta Basin Gathering System and general support equipment were retained by QEP and were not part of the assets conveyed to the Partnership.

Three Months Ended June 30, 2013 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $37.1 million for the three months ended June 30, 2013.

Natural gas gathering and transportation revenue was $32.3 million with throughput of 94.4 MMBtu and an average gas gathering and transportation fee of $0.34 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System which contributed 51.2 MMBtu of throughput; the Predecessor's Uinta Basin Gathering System with throughput of 18.8 MMBtu; and our Vermillion Gathering System with throughput of 12.0 MMBtu.

Crude oil and condensate gathering revenue was $2.9 million for the three months ended June 30, 2013, as a result of an average gathering fee of $2.14 per barrel and throughput of 1,380.8 MBbls of which 1,054.8 MBbls was attributable to our Green River Gathering System and 326.1 MBbls was attributable to our Williston Gathering System.

Water gathering revenue consisted of $1.9 million for the three months ended June 30, 2013, from throughput of 1,027.6 MBbls and an average fee of $1.83 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $3.0 million for the three months ended June 30, 2013, from sales volumes of 36.2 MBbls at a price of $80.96 per barrel, of which 22.7 MBbls was attributable to our Green River Gathering System, 10.2 MBbls was attributable to our Vermillion Gathering System and the remainder was attributable to the Predecessor's Uinta Basin Gathering System.

Operating Expenses

Gathering expense. Gathering expense was $8.3 million for the three months ended June 30, 2013, the majority of which was incurred on our Green River and Vermillion Gathering systems and the Predecessor's Uinta Basin Gathering System.

General and administrative. General and administrative expenses were $4.7 million for the three months ended June 30, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes. Taxes other than income taxes were $0.6 million for the three months ended June 30, 2013, primarily attributable to property tax expense on the gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $9.8 million for the three months ended June 30, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $2.1 million for the three months ended June 30, 2013. Of the $2.1 million, income from the Predecessor's ownership in Uintah Basin Field Services was $1.2 million and income from our ownership in Three Rivers Gathering was $0.9 million.

Interest expense. Interest expense was $1.0 million for the three months ended June 30, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP during the period.

Six Months Ended June 30, 2013 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $73.7 million for the six months ended June 30, 2013.

Natural gas gathering and transportation revenue was $63.4 million with throughput of 185.0 MMBtu and an average gas gathering and transportation fee of $0.34 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 98.6 MMBtu of throughput; the Predecessor's Uinta Basin Gathering System, with throughput of 36.9 MMBtu; and our Vermillion Gathering System, with throughput of 25.1 MMBtu.

Crude oil and condensate gathering revenue was $5.5 million for the six months ended June 30, 2013, as a result of an average gathering fee of $2.08 per barrel and throughput of 2,659.6 MBbls of which 2,027.3 MBbls was attributable to our Green River Gathering System and 632.3 MBbls was attributable to our Williston Gathering System.

Water gathering revenue consisted of $3.4 million for the six months ended June 30, 2013, from throughput of 1,897.7 MBbls and an average fee of $1.82 per barrel at our Green River Gathering System.

The remaining portion of gathering and transportation revenue for the six months ended June 30, 2013, related to deficiency revenue of $1.4 million, all of which was attributable to our Williston Gathering System.

Condensate sales. Revenue from condensate sales was $6.5 million for the six months ended June 30, 2013, from sales volumes of 78.9 MBbls at a price of $82.05 per barrel, all of which was attributable to our Vermillion Gathering System and the Predecessor's Uinta Gathering System.

Operating Expenses

Gathering expense. Gathering expense was $16.0 million for the six months ended June 30, 2013, the majority of which was incurred on the Predecessor's Uinta Basin Gathering System and our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $10.4 million for the six months ended June 30, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes. Taxes other than income taxes were $0.9 million for the six months ended June 30, 2013, primarily attributable to property tax expense on the gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $20.1 million for the six months ended June 30, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $3.4 million for the six months ended June 30, 2013. Of the $3.4 million, income from the Predecessor's ownership in Uintah Basin Field Services was $1.9 million and income from our ownership in Three Rivers Gathering was $1.5 million.

Interest expense. Interest expense was $2.1 million for the six months ended June 30, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP during the period.

Supplemental Pro Forma Analysis

As previously discussed, the historical financial information of the Predecessor contained in this report relates to periods that ended prior to the completion of the IPO, and includes results for both the properties conveyed to the Partnership in connection with the IPO and properties retained by our Predecessor. We believe that historical data limited to only the properties conveyed to the Partnership in connection with the IPO and that reflects transactions that occurred as a result of the IPO is relevant and meaningful, enhances the discussion of the periods presented and is useful to the reader to better understand trends in our operations. Therefore, we have also included the results of operations for the three and six months ended June 30, 2013, on a pro forma basis.

Supplemental Pro Forma Analysis - Successor Three Months Ended June 30, 2014, Compared to Pro Forma Three Months Ended June 30, 2013

Revenue

Gathering and transportation. Gathering and transportation revenues decreased by $0.3 million during the three months ended June 30, 2014, compared to the pro forma three months ended June 30, 2013.

Natural gas gathering and transportation revenues decreased $0.3 million, as a result of a 3% lower gas gathering rate due to an increase in volumes gathered from customers with lower gathering rates, partially offset by a higher gas gathering throughput of 0.2 MMBtu.

Crude oil and condensate gathering revenue decreased by $0.3 million during the three months ended June 30, 2014 compared to the pro forma three months ended June 30, 2013, due to a 19% decrease in gathering volumes, primarily at the Green River Gathering System, partially offset by a 12% increase in rate due to an increase in volumes gathered from customers with higher gathering rates. The decrease in gathering volumes is due to lower volumes gathered from third party producers in this area.

Water gathering revenue increased by $0.3 million, or 16%, due to a 14% increase in gathering volume and a 2% increase in rate on the Green River Gathering System.

Condensate sales. Condensate sales decreased by $0.8 million during the three months ended June 30, 2014, compared to the pro forma three months ended June 30, 2013, due to a 36% decrease in sales volumes at the Green River Gathering System, partially offset by a 5% increase in price as a result of our fixed-price sales agreement with QEP.

Operating Expenses

Gathering expense. Gathering expense decreased by $0.4 million, or 7%, during the three months ended June 30, 2014, compared to the pro forma three months ended June 30, 2013, primarily due to a decrease in labor expense at the Williston Gathering System.

General and administrative. General and administrative expenses for the three months ended June 30, 2014, increased by $1.1 million, or 27%, compared to the pro forma three months ended June 30, 2013, due to professional service fees incurred for the Green River Processing Acquisition.

Taxes other than income taxes. Taxes other than income taxes increased by $0.2 million during the three months ended June 30, 2014, compared to the pro forma three months ended June 30, 2013, due to increased property taxes at our Green River and Vermillion Gathering systems.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates decreased by $0.5 million during the three months ended June 30, 2014, compared to the pro forma three months ended June 30, 2013, due to deficiency revenue recognized in the second quarter of 2013 from our ownership in Three Rivers Gathering.

Interest expense. Interest expense during the three months ended June 30, 2014, was consistent with the pro forma three months ended June 30, 2013, as the pro forma adjustments include the assumption that related party debt was settled and that a consistent interest expense, including commitment fees and amortization of debt financing costs, would have been paid in the first quarter of 2013, as there would have been no borrowings under the Credit Facility.

Supplemental Pro Forma Analysis - Successor Six Months Ended June 30, 2014, Compared to Pro Forma Six Months Ended June 30, 2013

Revenue

Gathering and transportation. Gathering and transportation revenues decreased by $0.4 million during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013.

Natural gas gathering and transportation revenues decreased $2.4 million, as a result of lower gas gathering throughput of 2.5 MMBtu and a 3% lower gas gathering rate. The decrease in throughput was primarily attributable to a 3.5 MMBtu decrease at the Vermillion Gathering System, partially offset by a 0.9 MMBtu increase at the Green River Gathering System. The volume decrease at the Vermillion Gathering System is related to lower production from customers in this area. The gas gathering rate decrease is due to an increase in volumes gathered from customers with lower gathering rates.

Crude oil and condensate gathering revenue was $0.4 million lower during the six months ended June 30, 2014 compared to the pro forma six months ended June 30, 2013, due to a 18% decrease in gathering volume, partially offset by a 14% increase in price. The decrease in throughput was primarily attributable to 0.4 MBbls decrease at the Green River Gathering System and 0.1 MBbls decrease at the Williston Gathering System.

Water gathering revenue increased by $0.7 million, or 21%, due to a 19% increase in gathering volume and a 2% increase in rate on the Green River Gathering System.

Deficiency revenue increased by $1.7 million during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013, due to higher deficiency revenue attributable to the Williston Gathering System.

Condensate sales. Condensate sales decreased by $0.7 million during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013, due to a 18% decrease in sales volumes at the Green River Gathering System, partially offset by a 3% increase in price as a result of our fixed-price sales agreement with QEP.

Operating Expenses

Gathering expense. Gathering expense increased by $0.2 million, or 2%, during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013, due to increased labor and maintenance costs at our Vermillion and Williston Gathering Systems.

General and administrative. General and administrative expenses for the six months ended June 30, 2014, increased by $1.3 million, or 15%, compared to the pro forma six months ended June 30, 2013, due to professional service fees incurred for the Green River Processing Acquisition.

Taxes other than income taxes. Taxes other than income taxes increased by $0.5 million during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013, due to increased property taxes at the Green River Gathering System and the Vermillion Gathering System.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased by $0.4 million during the six months ended June 30, 2014, compared to the pro forma six months ended June 30, 2013, due to deficiency revenue recognized in the first half of 2013 from our ownership in Three Rivers Gathering.

Interest expense. Interest expense during the six months ended June 30, 2014, was consistent with the pro forma six months ended June 30, 2013, as the pro forma adjustments include the assumption that related party debt was settled and that a consistent interest expense, including commitment fees and amortization of debt financing costs, would have been paid in the first quarter of 2013, as there would have been no borrowings under the Credit Facility.

Adjusted EBITDA and Distributable Cash Flow (Non-GAAP)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	Successor			Predecessor			Successor			Predecessor
	(in millions)
Unaudited Reconciliation of Net Income Attributable to QEP Midstream or Predecessor to Adjusted EBITDA and Distributable Cash Flows
Net income attributable to QEP Midstream or Predecessor	$	9.9		$	16.4		$	21.6		$	31.8
Interest expense	0.5			1.0			1.1			2.1
Depreciation and amortization	8.2			9.8			16.0			20.1
Noncontrolling interest share of depreciation and amortization⁽¹⁾	(0.6		)	(0.3		)	(1.3		)	(1.0		)
Net loss from property sales	—			0.1			—			0.4
Adjusted EBITDA	$	18.0		$	27.0		$	37.4		$	53.4
Net cash interest paid	(0.4		)				(0.8		)
Maintenance capital expenditures	(3.1		)				(7.3		)
Reimbursements for maintenance capital expenditures	—						1.0
Cash adjustments related to equity method investments and non-controlling interest	1.3						2.7
Non-cash equity-based compensation expense	0.1						0.3
Distributable Cash Flow	$	15.9					$	33.3


⁽¹⁾	Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services.



	Six Months Ended June 30,
	2014			2013
	Successor			Predecessor
	(in millions)
Unaudited Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flows
Net cash provided by operating activities	$	39.9		$	63.4
Noncontrolling interest share of depreciation and amortization⁽¹⁾	(1.3		)	(1.0		)
Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates	(2.3		)	(0.7		)
Net income attributable to noncontrolling interest	(1.7		)	(1.9		)
Interest expense	1.1			2.1
Working capital changes	2.6			(8.5		)
Amortization of deferred financing charges	(0.3		)	—
Equity-based compensation expense	(0.6		)	—
Adjusted EBITDA	$	37.4		$	53.4
Net cash interest paid	(0.8		)
Maintenance capital expenditures	(7.3		)
Reimbursements for maintenance capital expenditures	1.0
Cash adjustments related to equity method investments and non-controlling interest	2.7
Non-cash equity-based compensation expense	0.3
Distributable Cash Flow	$	33.3


⁽¹⁾	Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services.

Liquidity and Capital Resources

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

Since the IPO, we have maintained our own bank accounts and sources of liquidity and continue to utilize QEP's cash management expertise. Our ongoing sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures include cash generated from operations, borrowings under our Credit Facility, and access to debt and equity markets. We 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 net cash provided by operating activities, investing activities and financing activities for the periods indicated.



	Six Months Ended June 30,
	2014			2013
	Successor			Predecessor

Net cash provided by (used in):
Operating activities	$	39.9		$	63.4
Investing activities	$	(11.4	)	$	(6.6	)
Financing activities	$	(31.0	)	$	(55.1	)

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



	Six Months Ended June 30,
	2014			2013
	Successor			Predecessor

Net income	$	23.3		$	33.7
Non-cash adjustments to net income	19.2			21.2
Changes in operating assets and liabilities	(2.6		)	8.5
Net cash provided by operating activities	$	39.9		$	63.4

Investing Activities. The Predecessor's historical capital expenditures were funded from a combination of cash provided by operating activities and funding from QEP. The Partnership's capital expenditures were funded from cash provided by operating activities. Capital expenditures for the six months ended June 30, 2014 and 2013, are presented in the following table:



	Six Months Ended June 30,
	2014		2013
	Successor		Predecessor

Total accrued capital expenditures	$	8.3	$	5.2
Change in accruals and non-cash items	3.1		2.3
Total cash capital expenditures	$	11.4	$	7.5

Financing Activities. For the six months ended June 30, 2014, the Partnership's cash used in financing activities consisted of $28.9 million in unitholder distributions paid in February 2014 and May 2014 as well as $3.1 million in distributions to its noncontrolling interest in Rendezvous Gas.

For the six months ended June 30, 2013, the Predecessor's cash used in financing activities primarily consisted of $43.7 million in repayments of long-term debt to QEP. In addition, the Predecessor made distributions to QEP of $8.3 million and paid distributions to its noncontrolling interest in Rendezvous Gas of $3.1 million for the six months ended June 30, 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 Field Services or third parties and the construction or development of additional pipeline capacity, well connections or compression, to the extent such expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is disposed of or abandoned.

Capital expenditures totaled $8.3 million for the Partnership for the six months ended June 30, 2014, which includes maintenance capital of $7.3 million and expansion capital of $1.0 million. Maintenance capital expenditures of $7.3 million include $5.4 million related to the Green River Gathering System, of which $3.1 million related to a compressor maintenance overhaul project, $1.3 million related to system maintenance, and $1.0 million related to a condensate pipeline repair and replacement project. The Partnership was reimbursed by QEP for the $1.0 million of pipeline repair costs pursuant to an indemnification provision in the Omnibus Agreement. The remaining maintenance capital expenditures of $1.9 million primarily related to compressor maintenance on the Vermillion Gathering System. Expansion capital expenditures of $1.0 million related primarily to a compressor replacement project on the Vermillion Gathering System and reimbursable well connects on the Williston Gathering System.

We expect our gross capital expenditures to range from $11.0 million to $14.0 million for the year ending December 31, 2014. This amount includes approximately $10.0 million to $12.0 million of maintenance capital and approximately $1.0 million to $2.0 million of expansion capital. Maintenance capital spending includes compressor maintenance projects primarily in the Green River and Vermillion areas, well connects in the Green River area, and gathering system modifications in the Green River area. Expansion capital spending includes expansion reimbursable well connects in the Williston Gathering System and a compression upgrade in the Vermillion Gathering System. In addition to capital expenditures related to our consolidated assets, we expect to make contributions to Green River Processing related to maintenance capital expenditures for approximately $1.0 million to $2.0 million. Capital spending may vary significantly from period to period based on the investment opportunities available to us and the timing of large maintenance items. We expect to fund the 2014 capital expenditures with cash provided by operating activities and borrowings under our Credit Facility.

Distributions

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

On April 22, 2014, the Partnership declared its quarterly cash distribution totaling $14.7 million, or $0.27 per unit, for the first quarter of 2014. This quarterly distribution was paid on May 15, 2014, to unitholders of record as of the close of business on May 5, 2014.

On July 22, 2014, the Partnership declared its quarterly cash distribution totaling $15.3 million, or $0.28 per unit, for the second quarter of 2014. This quarterly distribution will be paid on August 14, 2014, to unitholders of record as of the close of business on August 4, 2014.

No distributions related to the General Partner's incentive distribution rights were declared.

At a minimum, we plan to pay a quarterly distribution of $0.25 per unit, which equates to $13.6 million per quarter, or $54.5 million per year, based on the number of common, subordinated and general partner units outstanding. Although our Partnership Agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit. Refer to Item 5 of Part II of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013, for additional information.

Credit Facility

In connection with the IPO, we entered into the Credit Facility, a $500.0 million senior secured revolving credit agreement, with a group of financial institutions, with a maturity date of August 14, 2018. The Credit Facility contains an accordion provision that allows the amount of the facility to be increased to $750.0 million with the agreement of the lenders. The Credit Facility is available for working capital, capital expenditures, permitted acquisitions and general corporate purposes, including distributions. Substantially all of the Partnership's assets, excluding equity in and assets of certain joint ventures and unrestricted subsidiaries and other customary exclusions, are pledged as collateral under the Credit Facility. In addition, the Credit Facility contains restrictions and events of default customary for transactions of this nature.

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

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


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


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


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

There were no borrowings under the Credit Facility during the three and six months ended June 30, 2014. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.325% to 0.500% per annum. For the three and six months ended June 30, 2014, the Partnership incurred $0.4 million and $0.8 million, respectively, of commitment fees.

As of July 31, 2014, the Credit Facility had an outstanding balance of $223.5 million. All borrowings under the Credit Facility were related to financing the Green River Processing Acquisition, which closed on July 1, 2014.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include companies that may react differently to changing conditions. Our principal customers are QEP and Questar Gas Company (QGC), who accounted for approximately 69% and 15%, respectively, of the Partnership's total revenues for the six months ended June 30, 2014. We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including QEP and QGC. Consequently, we are subject to the risk of non-payment or late payment by QEP and QGC of gathering fees, and this risk is greater than it otherwise would be with a broader customer base with a similar credit profile.

Our gathering agreement with QGC is the subject of ongoing litigation in which QGC is disputing the calculation of the gathering rate and has been netting the disputed amount from its monthly payment of gathering fees to QEP Field Services and the Partnership since the second quarter of 2012. As of June 30, 2014, the Partnership has deferred revenue of $11.6 million related to the QGC disputed amount. The Partnership has been indemnified by QEP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement. For more information regarding the litigation with QGC, refer to Note 9 - Commitments and Contingencies, in Item 1 of Part I and Legal Proceedings in Item I of Part II of this Quarterly Report on Form 10-Q.

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

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

Related Parties

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of June 30, 2014, QEP Field Services owns 3,701,750 common units and 26,705,000 subordinated units representing a 55.8% limited partner interest in us. In addition, our General Partner owns 1,090,286 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEP Field Services and QEP are considered to be related party transactions, because our General Partner and its affiliates own more than 5% of our equity interests.

In connection with the IPO, QEP Midstream entered into various agreements with QEP Field Services, QEP and our General Partner including, but not limited to, the following: the Omnibus Agreement, the Partnership Agreement, gathering and transportation agreements, a fixed priced condensate purchase agreement, operating agreements and other service agreements. During the three and six months ended June 30, 2014, approximately 69% of our revenue came from QEP. Prior to the IPO, the Predecessor had other agreements in place with QEP resulting in related party transactions. For the three and six months ended June 30, 2013, QEP accounted for 51% of the Predecessor's total revenue. Refer to Note 4 - Related Party Transactions, in Item 1 of Part I of this Quarterly Report on Form 10-Q for additional information on related party transactions for the Pre and Post-IPO Periods.

Critical Accounting Policies

During the six months ended June 30, 2014, there were no significant changes to our critical accounting policies and estimates as disclosed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2013.

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Company is currently assessing the impact on the Company's consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Prior to the IPO, our Predecessor's interest expense was an allocation of QEP Field Service's interest expense on debt which consisted of two promissory notes between QEP Field Services and QEP, each with a fixed rate of 6.0%. The Partnership's Credit Facility contains a variable interest rate that exposes us to volatility in interest rates. Since the Credit Facility was put in place, there has been no debt outstanding under the Credit Facility, and therefore we have not had 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, in conjunction with the IPO, the Partnership entered into a fixed-price Condensate Purchase Agreement with QEP, which requires us to sell and QEP to purchase all of the condensate volumes collected on our gathering systems at a fixed price of $85.25 per barrel of product over a primary term of five years. In addition, we expect to utilize risk management tools to minimize future commodity price risk that could be associated with assets we may acquire or contracts we may enter into in the future.

Forward-Looking Statements

This Quarterly Report on Form 10-Q 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. We use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements include statements relating to, among other things:


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


•	favorable terms of related party agreements;


•	organic growth from our existing assets;


•	competitive advantage in attracting additional third-party volumes on our systems;


•	our financial flexibility and strong capital structure;


•	fees charged for firm service;


•	benefits provided by our relationship with QEP;


•	seasonality of our business;


•	estimated amounts and allocation of capital expenditures;


•	factors affecting the comparability of our operating results;


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


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


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


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


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


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


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


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


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


•	anticipated general and administrative expenses;


•	the significance of Adjusted EBITDA and Distributable Cash Flow as performance measures;


•	trends impacting our business;


•	impact of QEP's separation of its midstream business on our acquisition opportunities and growth;


•	anticipated levels of exploration and production activities in the areas we operate;


•	impact of oil and natural gas prices on production rates;


•	decline in production from the various properties dedicated to our gathering systems;


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


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


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


•	acquisitions of additional midstream assets from QEP Field Services and third parties;


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


•	amount, funding and timing of future cash distributions;


•	variance of expansion capital expenditures from period to period;


•	funding for acquisition and expansion capital expenditures during 2014;


•	maintenance of separate accounts and utilization of QEP's cash management systems and expertise;


•	sources of liquidity;


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


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


•	impact of QEP's and QGC's, as our largest customers, failure to perform under the terms of our gathering agreements;


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


•	usefulness of historical data related only to properties conveyed to us in the IPO;


•	supplemental pro forma disclosures;


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


•	compliance with internal controls framework.

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


•	the risk factors discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013;


•	outcome of QEP's efforts to separate its midstream business;


•	changes in general economic conditions;


•	competitive conditions in our industry;


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


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


•	our ability to successfully implement our business plan;


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


•	the price and availability of debt and equity financing;


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


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


•	operating risks and hazards incidental to transporting, storing and processing oil and natural gas, as applicable;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	production trends in our areas of operations;


•	interest rates;


•	labor relations;


•	large customer defaults;


•	changes in availability and cost of capital;


•	changes in tax status;


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


•	the effects of future litigation.

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

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, 2014. Based on such evaluation, our management has concluded that, as of June 30, 2014, 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 our 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

The Partnership maintains a system of internal controls over financial reporting that is designed to provide reasonable assurance that its books and records accurately reflect transactions and that established policies and procedures are followed. During the quarter ended June 30, 2014, QEP completed the implementation of a new enterprise resource planning (ERP) system. The ERP system was implemented by QEP to improve standardization and automation, and not in response to a deficiency in internal control over financial reporting. Management believes the implementation of the ERP system and related changes to internal controls will enhance the Partnership's internal controls over financial reporting while providing the ability to scale the Partnership's business in the future. The Partnership and QEP have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change and will continue to evaluate the operating effectiveness of related key controls during subsequent periods.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control - Integrated Framework (the 2013 Framework). Originally issued in 1992 (the 1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of June 30, 2014, we have initiated the process to ensure we are in compliance with the 2013 Framework, and we anticipate we will be in compliance by the required due date of December 15, 2014.

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth under Litigation in "Note 9 - Commitments and Contingencies" to the Partnership'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 Partnership are set forth under Risk Factors in Part I, Item 1A of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2013. No material changes to such risk factors have occurred during the three months ended June 30, 2014.

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

None.

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
10.1		Purchase and Sale Agreement, dated May 7, 2014, by and among QEP Field Services Company, QEP Midstream Partners GP, LLC, QEP Midstream Partners Operating LLC, and QEP Midstream Partners, LP (Incorporated by reference to Exhibit No. 10.1 to the Partnership's Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 8, 2014.)
31.1		Certification signed by C. B. Stanley, Chief Executive Officer of QEP Midstream Partners GP, LLC, General Partner of QEP Midstream Partners, LP, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, Chief Financial Officer of QEP Midstream Partners GP, LLC, General Partner of QEP Midstream Partners, LP, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification signed by Charles B. Stanley and Richard J. Doleshek, Chief Executive Officer and Chief Financial Officer, respectively, of QEP Midstream Partners GP, LLC, General Partner of QEP Midstream Partners, LP, 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)

August 7, 2014		/s/ Charles B. Stanley
		Charles B. Stanley,
		Chairman, President and Chief Executive Officer

August 7, 2014		/s/ Richard J. Doleshek
		Richard J. Doleshek,
		Executive Vice President and Chief Financial Officer

Attached files

QEP Midstream Partners, LP Reports

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