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EX-31.2 - EXHIBIT 31.2 - QEP Midstream Partners, LPqepm-20140930xex312.htm
EX-32.1 - EXHIBIT 32.1 - QEP Midstream Partners, LPqepm-20140930xex321.htm
EX-31.1 - EXHIBIT 31.1 - QEP Midstream Partners, LPqepm-20140930xex311.htm
EXCEL - IDEA: XBRL DOCUMENT - QEP Midstream Partners, LPFinancial_Report.xls



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 September 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 17th 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 26,729,240 common units, 26,705,000 subordinated units and 1,090,495 general partner units outstanding on October 31, 2014









QEP Midstream Partners, LP
Form 10-Q for the Quarter Ended September 30, 2014

TABLE OF CONTENTS
 
 
 
 
Page
 
 
 
 
 
ITEM 1.
 
 
 
 
 
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
 
 
UNAUDITED CONDENSED CONSOLDIATED BALANCE SHEETS
 
 
 
 
 
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
 
 
 
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EQUITY
 
 
 
 
 
 
UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
 
 
ITEM 1.
 
 
 
 
 
ITEM 1A.
 
 
 
 
 
ITEM 2.
 
 
 
 
 
ITEM 3.
 
 
 
 
 
ITEM 4.
 
 
 
 
 
ITEM 5.
 
 
 
 
 
ITEM 6.
 
 






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 condensed 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
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
Three Months Ended September 30, 2014

Period from August 14, 2013 to September 30, 2013

Period from July 1, 2013 to August 13, 2013

Nine Months Ended September 30, 2014

Period from August 14, 2013 to September 30, 2013

Period from January 1, 2013 to August 13, 2013

Successor

Successor

Predecessor

Successor

Successor

Predecessor
 
(in millions, except per unit amounts)
Revenues

 

 
 




 
 
Gathering and transportation
$
28.6


$
16.2


$
19.2


$
85.9


$
16.2


$
92.9

Condensate sales
0.1


0.2


0.9


4.0


0.2


7.4

Total revenues
28.7


16.4


20.1


89.9


16.4


100.3

Operating expenses











Gathering expense
5.8


3.1


3.7


17.6


3.1


19.7

General and administrative
4.1


1.5


3.2


14.0


1.5


13.6

Taxes other than income taxes
0.5


0.3


0.4


1.5


0.3


1.3

Depreciation and amortization
8.0


4.1


4.9


24.0


4.1


25.0

Total operating expenses
18.4


9.0


12.2


57.1


9.0


59.6

Net loss from property sales




(0.1
)





(0.5
)
Operating income
10.3


7.4


7.8


32.8


7.4


40.2

Income from unconsolidated affiliates
5.9




0.4


7.8




3.8

Interest expense
(1.5
)

(0.3
)

(0.5
)

(2.6
)

(0.3
)

(2.6
)
Net income
14.7


7.1


7.7


38.0


7.1


41.4

Net income attributable to noncontrolling interest
(1.0
)

(0.6
)

(0.6
)

(2.7
)

(0.6
)

(2.5
)
Net income attributable to QEP Midstream or Predecessor
$
13.7


$
6.5


$
7.1


$
35.3


$
6.5


$
38.9




 


 
 






 
 
Net income attributable to QEP Midstream per limited partner unit (basic and diluted):
 
 
 
 
 
 
Common units
$
0.25


$
0.12

 
 

$
0.65


$
0.12

 
 
Subordinated units
$
0.25


$
0.12

 
 

$
0.65


$
0.12

 
 



 


 
 






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


26.7

 
 

26.7


26.7

 
 
Subordinated units
26.7


26.7

 
 

26.7


26.7

 
 
Cash distributions per unit (1)
$
0.30


$
0.13





$
0.85


$
0.13




            
(1)    Represents the cash distributions declared related to the period presented.

See notes accompanying the unaudited condensed consolidated financial statements.
 


3



QEP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
 
September 30, 2014

December 31, 2013

Successor

Successor
 
(in millions)
ASSETS



Current assets:



Cash and cash equivalents
$
15.4


$
19.0

Accounts receivable, net
12.0


9.1

Accounts receivable from related party
28.7


25.5

Natural gas imbalance receivable
21.3


1.7

Total current assets
77.4


55.3

Property, plant and equipment, net
481.8


493.4

Investment in unconsolidated affiliates
134.3


27.8

Other noncurrent assets
2.8


3.4

Total assets
$
696.3


$
579.9

LIABILITIES



Current liabilities:



Accounts payable
$
5.2


$
6.6

Accounts payable to related party
3.0


9.0

Natural gas imbalance liability
21.3


1.7

Deferred revenue
14.7


9.6

Other current liabilities
1.5


0.2

Total current liabilities
45.7


27.1

Long-term debt
230.0

 

Asset retirement obligation
14.0


13.3

Deferred revenue
11.2


11.9

Total long-term liabilities
255.2


25.2

Commitments and contingencies (see Note 10)



EQUITY



Limited partner common units - 26.7 million units issued and outstanding
393.4


411.7

Limited partner subordinated units - 26.7 million units issued and outstanding
(40.0
)

68.0

General partner units - 1.1 million units issued and outstanding
(1.5
)

2.5

Total partners' capital
351.9


482.2

Noncontrolling interest
43.5


45.4

Total equity
395.4


527.6

Total liabilities and equity
$
696.3


$
579.9


 


 

See notes accompanying the unaudited condensed consolidated financial statements.


4



QEP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended September 30,
 
Nine Months Ended September 30, 2014

Period from August 14, 2013 to September 30, 2013

Period from January 1, 2013 to August 13, 2013
 
Successor

Successor

Predecessor
 
(in millions)
OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
38.0


$
7.1


$
41.4

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





Depreciation and amortization
24.0


4.1


25.0

Equity-based compensation expense
0.7


0.1



Income from unconsolidated affiliates
(7.8
)



(3.8
)
Distributions from unconsolidated affiliates
6.5




3.8

Amortization of debt issuance costs
0.5


0.1


0.5

Changes in operating assets and liabilities:

 

 

Accounts receivable
(6.1
)
 
6.4

 
17.8

Accounts payable and accrued expenses
(4.6
)
 
(6.0
)
 
8.9

Other
5.6

 
2.0

 
(3.8
)
Net cash provided by operating activities
56.8

 
13.8

 
89.8

INVESTING ACTIVITIES
 
 
 
 
 
Property, plant and equipment
(14.4
)

(2.2
)

(9.1
)
Equity investments
(106.9
)




Contribution to equity investment
(1.1
)






Distributions from equity investments in excess of cumulative earnings
2.9


0.4


1.1

Proceeds from sale of assets




0.6

Net cash used in investing activities
(119.5
)
 
(1.8
)
 
(7.4
)
FINANCING ACTIVITIES

 

 

Issuance of long-term debt
284.5





Repayments of long-term debt
(54.5
)

(95.5
)

(66.4
)
Long-term debt issuance costs


(3.0
)


Net proceeds from initial public offering


449.6



Proceeds from initial public offering distributed to parent


(351.1
)


Contributions from (distributions to) parent, net
1.0


3.0


(12.2
)
Green River Processing Acquisition – purchase price in excess of net assets acquired
(123.1
)




Distributions to unitholders
(44.2
)




Distribution to noncontrolling interest
(4.6
)

(0.2
)

(4.1
)
Net cash provided by (used in) financing activities
59.1

 
2.8

 
(82.7
)
Change in cash and cash equivalents
(3.6
)
 
14.8

 
(0.3
)
Beginning cash and cash equivalents
19.0

 
1.1

 
1.4

Ending cash and cash equivalents
$
15.4

 
$
15.9

 
$
1.1

 
 
 
 
 
 
Supplemental Disclosures:
 
 
 
 
 
Non-cash investing activities
 
 
 
 
 
Change in capital expenditure accrual balance
$
(2.8
)
 
$
2.5

 
$
(1.6
)
See notes accompanying the unaudited condensed consolidated financial statements.


5



QEP MIDSTREAM PARTNERS, LP
CONDENSED CONSOLIDATED STATEMENT OF EQUITY
(Unaudited)



Successor


Limited Partners










Common Units

Subordinated Units

General Partner Units

Noncontrolling
Interest

Total Net Equity


Units

Amount

Units

Amount

Units

Amount






(in millions)
Balance at December 31, 2013

26.7

 
$
411.7

 
26.7

 
$
68.0

 
1.1

 
$
2.5

 
$
45.4


$
527.6

Contributions from parent


 
0.1

 

 
0.9

 

 

 


1.0

Distributions to noncontrolling interest


 

 

 

 

 

 
(4.6
)

(4.6
)
Distributions to unitholders


 
(21.6
)
 

 
(21.6
)
 

 
(1.0
)
 


(44.2
)
Equity-based compensation


 
0.7

 

 

 

 

 


0.7

Purchase price in excess of net assets from Green River Processing Acquisition


 
(14.8
)
 

 
(104.6
)
 

 
(3.7
)
 


(123.1
)
Net income


 
17.3

 

 
17.3

 

 
0.7

 
2.7


38.0

Balance at September 30, 2014

26.7


$
393.4

 
26.7

 
$
(40.0
)
 
1.1

 
$
(1.5
)
 
$
43.5


$
395.4


See notes accompanying the unaudited condensed consolidated financial statements.


6



QEP MIDSTREAM PARTNERS, LP
NOTES ACCOMPANYING THE CONDENSED 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. In addition, in July 2014, the Partnership acquired a 40% interest in Green River Processing, LLC. Refer to Note 3 - Acquisitions for further detail.

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 4 - 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.

In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate QEP’s midstream business (QEP Field Services), including the ownership and control of QEP Midstream. In October 2014, QEP, through its wholly owned subsidiary, QEP Field Services, entered into a definitive agreement to sell its midstream business to Tesoro Logistics LP (Tesoro) in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance the Partnership's debt. In addition to other midstream assets, QEP Field Services owns (i) QEP Midstream's general partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership's incentive distribution rights and (ii) an approximate 56% limited partner interest in the Partnership. Upon closing, Tesoro will own and control the Partnership's general partner. The transaction does not involve the sale or purchase of any QEP Midstream common units held by the public. The transaction is subject to customary closing conditions and regulatory approvals and is expected to close in the fourth quarter of 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction.

Note 2 - Basis of Presentation of Interim Condensed Consolidated Financial Statements

Basis of Presentation

The interim unaudited condensed 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 condensed 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

7



the results of operations and financial position. Amounts reported in the Unaudited Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods.

The unaudited condensed 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 April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The ASU currently has no impact on the Partnership's consolidated financial statements as no divestitures have occurred.

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.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Partnership is currently evaluating the impact of this standard on its financial statements.

Note 3 - Acquisitions

Green River Processing 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). Green River Processing owns the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming.

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 is accounted for as an equity investment in an unconsolidated affiliate. The investment has been recorded at the historical carrying value of $106.9 million 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. The carrying value of the net property, plant and equipment less asset retirement obligations was used, as these were the only assets, liabilities or working capital of Green River Processing operations that were conveyed by QEP Field Services in conjunction with the Green River Processing Acquisition. The portion recorded to equity was allocated among the equity owned by QEP Field Services based upon the respective unit balances as of June 30, 2014, and no portion was allocated to the public ownership in QEP Midstream.


8



Green River Processing Acquisition purchase price
 
 
$
230.0

 
 
 
 
 
 
 
 
 
 
 
 
QEPFS' historic carrying value
$
267.3

 
 
 
 
 
 
QEP Midstream's acquired 40% interest of historic carrying value
 
 
106.9

 
 
 
 
Total equity contribution
 
 
$
123.1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity Allocation
 
QEP Field Services Units as of June 30, 2014
 
% Ownership
Limited partner common units - QEPFS
 
 
$
14.8

 
3,701,750

 
12
%
Limited partner subordinated units
 
 
104.6

 
26,705,000

 
85
%
General partner units
 
 
3.7

 
1,090,286

 
3
%
Total QEP Midstream
 
 
$
123.1

 
31,497,036

 
100
%

Note 4 - 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



9



As of September 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
 
23,027,490

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

 
49.0
%
General partner units
 
1,090,495

 
2.0
%
Total QEP Midstream units
 
54,524,735

 
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



10



Note 5 - Related Party Transactions

The following table summarizes the related party income statement transactions of the Partnership and Predecessor with QEP:
 
 
Three Months Ended September 30, 2014
 
Period from August 14, 2013 to September 30, 2013
 
Period from July 1, 2013 to August 13, 2013
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013 to September 30, 2013
 
Period from January 1, 2013 to August 13, 2013
 
 
Successor
 
Successor
 
Predecessor
 
Successor
 
Successor
 
Predecessor
 
 
(in millions)
Revenues from affiliate
 
$
19.5

 
$
11.2

 
$
12.1

 
$
62.0

 
$
11.2

 
$
53.4

General and administrative to affiliate
 
(3.5
)
 
(1.2
)
 
(3.2
)
 
(10.4
)
 
(1.2
)
 
(13.6
)
Interest expense to affiliate
 

 

 
(0.5
)
 

 

 
(2.6
)

The Partnership
Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of September 30, 2014, QEP Field Services owned 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 owned 1,090,495 general partner units representing a 2.0% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, 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 4 - 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 nine months ended September 30, 2014, the Partnership was charged $3.5 million and $10.4 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.

Green River Processing Annual G&A Services Fee
As part of the Green River Processing Acquisition, QEP Midstream became party to the Green River Processing, LLC Limited Liability Company Agreement, which provides that Green River Processing will pay QEP Field Services an annual general and administrative services fee of $7.0 million.

11




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, with a maturity date of April 1, 2014. In addition, QEP Field Services entered into a $1.0 billion revolving credit type promissory note with QEP, 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 were $3.2 million for the period from July 1, 2013, through August 13, 2013, and $13.6 million for the period from January 1, 2013, through August 13, 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 6 - Property, Plant and Equipment

A summary of the historical cost of the Partnership's property, plant and equipment is as follows: 
 
 
Estimated Useful
Lives
 
September 30, 2014
 
December 31, 2013
 
 
 
 
Successor
 
Successor
 
 
 
 
(in millions)
Gathering equipment
 
5 to 40 years
 
$
749.4

 
$
737.9

Accumulated depreciation
 
 
 
(267.6
)
 
(244.5
)
Total net property, plant and equipment
 
 
 
$
481.8

 
$
493.4


Note 7 - 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 period specified below (in millions):

12



 
Asset Retirement
Obligations
ARO liability at January 1, 2014
$
13.3

Accretion
0.6

Liabilities incurred
0.1

ARO liability at September 30, 2014
$
14.0



Note 8 - Debt

In connection with the IPO, the Partnership 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 September 30, 2014, there was $230.0 million outstanding under the Credit Facility, and the Partnership was in compliance with the covenants under the credit agreement. During the nine months ended September 30, 2014, QEP Midstream's weighted average interest rate on borrowings was 1.94%. 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). All debt outstanding prior to and at the IPO relates to intercompany debt with QEP discussed in Note 5 - 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 9 - 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
On March 17, 2014, the Board granted 8,289 common units to the non-employee directors of the Board at $23.53 per unit, which vested immediately. On August 14, 2014, the Board granted 2,343 common units to non-employee directors of the Board at $25.62 per unit, which vested immediately. The fair value of common unit awards granted to non-employee directors is based on the fair market value of the Partnership's common units on the date of the grant, and the equity-based compensation expense is recognized at the time of grant, because the common unit awards vest immediately and are non-forfeitable.

Phantom Units
During the nine months ended September 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

13



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 September 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

Vested
 
(12,759
)
 
22.03

Forfeited
 
(845
)
 
23.68

Unvested balance at September 30, 2014
 
38,085

 
$
22.58


Total compensation expense recognized for the common unit and phantom unit awards for the three and nine months ended September 30, 2014, was $0.1 million and $0.7 million, respectively, and the total amount of unrecognized compensation cost related to the phantom unit award was $0.5 million as of September 30, 2014, which is expected to be recognized over the remaining vesting period of 2.0 years.

Note 10 - 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, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the Offering, the assets and agreement discussed above were assigned to the Partnership. QGC amended its complaint to add the Partnership, QEP Midstream Partners GP, LLC, QEP Midstream Partners Operating, LLC and QEPM Gathering I, LLC as defendants 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 entered into between the Partnership and QEP in connection with the IPO (defined above in Note 5 - Related Party Transactions). QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to the Partnership. As of September 30, 2014, the Partnership has deferred revenue of $13.2 million related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement.


14



Note 11 - 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 (IDRs). 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 September 30, 2014, the basic net income per unit and the diluted net income per unit were equal as there were no 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 nine months ended September 30, 2014.

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
Three Months Ended September 30, 2014
 
Period from August 14, 2013 to September 30, 2013
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013 to September 30, 2013
 
 
(in millions)
Net income attributable to QEP Midstream
 
$
13.7

 
$
6.5

 
$
35.3

 
$
6.5

General partner's distribution declared (including IDRs)(1)
 
(0.4
)
 
(0.1
)
 
(1.0
)
 
(0.1
)
Limited partners' distribution declared on common units(1)
 
(8.0
)
 
(3.5
)
 
(22.7
)
 
(3.5
)
Limited partners' distribution declared on subordinated units(1)
 
(8.0
)
 
(3.5
)
 
(22.7
)
 
(3.5
)
Distribution in excess of net income attributable to QEP Midstream
 
$
(2.7
)
 
(0.6
)
 
$
(11.1
)
 
(0.6
)
(1) On October 22, 2014, the Partnership declared its quarterly cash distribution totaling $16.4 million, or $0.30 per unit for the third quarter of 2014. The quarterly distribution will be paid on November 14, 2014, to unitholders of record as of the close of business on November 4, 2014.



Three Months Ended September 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 (including IDRs)

$
0.4


$
8.0


$
8.0


$
16.4

Distributions in excess of net income attributable to QEP Midstream

(0.1
)

(1.3
)

(1.3
)

(2.7
)
Net income attributable to QEP Midstream

$
0.3


$
6.7


$
6.7


$
13.7










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



$
0.25


$
0.25






15




 
Nine Months Ended September 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 (including IDRs)
 
$
1.0

 
$
22.7

 
$
22.7

 
$
46.4

Distributions in excess of net income attributable to QEP Midstream
 
(0.3
)
 
(5.4
)
 
(5.4
)
 
(11.1
)
Net income attributable to QEP Midstream
 
$
0.7

 
$
17.3

 
$
17.3

 
$
35.3

 
 
 
 
 
 
 
 
 
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
 
 
 
$
0.65

 
$
0.65

 
 


 
 
Period from August 14, 2013 to September 30, 2013
 
 
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 (including IDRs)
 
$
0.1

 
$
3.5

 
$
3.5

 
$
7.1

Distributions in excess of net income attributable to QEP Midstream
 

 
(0.3
)
 
(0.3
)
 
(0.6
)
Net income attributable to QEP Midstream
 
$
0.1

 
$
3.2

 
$
3.2

 
$
6.5

 
 
 
 
 
 
 
 
 
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
 
 
 
$
0.12

 
$
0.12

 
 



16



Note 12 - Subsequent Events

Distribution
On October 22, 2014, the Partnership declared a quarterly cash distribution totaling $16.4 million, or $0.30 per unit for the third quarter of 2014. The quarterly distribution will be paid on November 14, 2014, to unitholders of record as of the close of business on November 4, 2014.

QEP Field Services Separation
In October 2014, QEP, through its wholly owned subsidiary, QEP Field Services, entered into a definitive agreement to sell its midstream business to Tesoro Logistics LP in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance the Partnership's debt. In addition to other midstream assets, QEP Field Services owns (i) QEP Midstream's general partner, which owns a 2% general partner interest in the Partnership and the Partnership's incentive distribution rights and (ii) an approximate 56% limited partner interest in the Partnership. Upon closing, Tesoro will own and control the Partnership's general partner. The transaction does not involve the sale or purchase of any QEP Midstream common units held by the public. The transaction is subject to customary closing conditions and regulatory approvals and is expected to close in the fourth quarter of 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction.

17



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 condensed 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.

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 Company (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 Partnership's $500 million revolving credit facility (the Credit Facility) and cash on hand.

The Partnership's assets consist of ownership interests in four gathering systems and two FERC-regulated pipelines through which we provide natural gas and crude oil gathering and transportation services. Additionally, we have a 40% interest in two gas processing complexes through the Green River Processing Acquisition. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the 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 365 miles of natural gas gathering pipelines, 132 miles of crude oil gathering pipelines, 25 miles of water gathering pipelines and a 60-mile, FERC-regulated crude oil pipeline located in the Green River Basin. These assets have 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-

18



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.
Green River Processing. Green River Processing owns the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming. The aggregate processing capacity of Green River Processing is 890 MMcf per day, comprised of 560 MMcf per day of cryogenic processing capacity and 330 MMcf per day of Joule-Thomson processing capacity. In addition, there is 15,000 barrels per day of NGL fractionation capacity at the Blacks Fork processing complex.
Vermillion Gathering System. The Vermillion Gathering System consists of gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah, which, when combined, include 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 provided supplemental pro forma historical data limited to only the properties conveyed to us in connection with the IPO, as we believe such data is more useful to the reader to better understand trends in our operations.

Recent Developments

In December 2013, QEP’s Board of Directors authorized QEP’s management to develop a plan to separate QEP’s midstream business (QEP Field Services), including the ownership and control of QEP Midstream. In October 2014, QEP, through its wholly owned subsidiary, QEP Field Services, entered into a definitive agreement to sell its midstream business to Tesoro Logistics LP (Tesoro) in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance the Partnership's debt. In addition to other midstream assets, QEP Field Services owns (i) QEP Midstream's general partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership's incentive distribution rights and (ii) an approximate 56% limited partner interest in the Partnership. Upon closing, Tesoro will own and control the Partnership's general partner. The transaction does not involve the sale or purchase of any QEP Midstream common units held by the public. The transaction is subject to customary closing conditions and regulatory approvals and is expected to close in the fourth quarter of 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction.
 
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.

19




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. 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.

With the Green River Processing Acquisition, our activities have expanded to include the processing of natural gas to separate natural gas liquids (NGL) from the natural gas, fractionating the resulting NGL into the various components and selling or delivering pipeline quality natural gas and NGL to various industrial and energy markets as well as interstate pipeline systems. Our results from Green River Processing are primarily driven by commodity prices for NGL and natural gas, as well as the volumes of natural gas we process under fee-based agreements. Our commodity price exposure has increased in connection with the Green River Processing Acquisition, as Green River Processing is party to a number of keep-whole processing agreements, which expose us to the spread between NGL product prices and the purchase price of natural gas (frac spread).

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 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.

Operating 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.

20




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. Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to net income attributable to the Partnership or the Predecessor, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow exclude some, but not all, items that affect net income attributable to the Partnership or the Predecessor and net cash provided by operating activities, and these measures may vary among other companies. As a result, Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

General Trends and Outlook

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

Oil and natural gas supply and demand

Our gathering operations are primarily dependent upon 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.


21



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.

Frac spread
A portion of our operations are based on keep-whole processing agreements. Under our keep-whole processing agreements, we are exposed to the spread between NGL product sales price and the purchase price of natural gas. In recent years U.S. exploration and production companies have shifted capital to liquids-rich gas areas and caused NGL production to increase dramatically. Increased NGL production, and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening in NGL prices, particularly ethane. We expect that ethane prices will continue to be range-bound until new crackers are built. The prices of heavier components of the NGL barrel have weakened recently in conjunction with the decline in global crude oil prices.

Impact of interest rates

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

Regulatory compliance

The regulation of 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.

Investment in Green River Processing

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, a wholly owned subsidiary of QEP Field Services, from QEP Field Services for $230.0 million. Green River Processing owns the Blacks Fork processing complex and the Emigrant Trail processing plant, both of which are located in southwest Wyoming. The Green River Processing Acquisition is accounted for as an equity method investment in an unconsolidated affiliate.

22




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. The Predecessor's general and administrative expenses included costs allocated by QEP. These costs were reimbursed and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources, and (iii) compensation, share-based compensation, benefits and pension and post-retirement costs. General and administrative expenses allocated to the Predecessor was $3.2 million for the period from July 1, 2013, through August 13, 2013, and $13.6 million for the period from January 1, 2013, through August 13, 2013.

In connection with the IPO, the Partnership entered into the Omnibus Agreement which establishes the general and administrative expense that QEP will charge the Partnership. 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 nine months ended September 30, 2014, the Partnership incurred $3.5 million and $10.4 million, respectively, of such administrative and operational services expenses.

In addition to the charges under the Omnibus Agreement, we incur 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 and expenses relating to events such as asset acquisitions. For the three and nine months ended September 30, 2014, the Partnership incurred $0.6 million and $3.6 million, respectively, of incremental general and administrative expenses, which includes $0.3 million and $1.4 million, respectively, 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, excluding acquisitions, have been funded by our working capital. This impacts the comparability of our cash flow statements, working capital analysis and liquidity discussion.

Interest expense

Prior to the IPO, we incurred interest expense on 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 million revolving credit facility agreement, which contains customary short-term interest rates and a commitment fee on the unused portion of the facility.

23




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 the 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.

Seasonality

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

24



Results of Operations

The discussion of our historical performance and financial condition is presented for the Partnership (Successor), for the three and nine months ended September 30, 2014, and the period from August 14, 2013 through September 30, 2013, and for the Predecessor for the period from July 1, 2013, through August 13, 2013 and the period from January 1, 2013, through August 13, 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 nine months ended September 30, 2013, on a pro forma basis.

The supplemental pro forma financial data is for informational purposes only and was derived from the Predecessor financial information adjusted to give effect to events and circumstances that are directly attributed to the IPO transaction as if it had occurred on January 1, 2013, that are factually supportable and, with respect to the Condensed Consolidated Statements of Income, are expected to have a continuing impact on the consolidated results. These adjustments include: removing the results of the assets retained by the Predecessor, consisting of the Uinta Basin Gathering System and general support equipment; adjusting general and administrative expense to eliminate general and administrative expense allocated to the Predecessor by QEP and to include 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 adjusting interest expense to eliminate the related party debt that was settled in conjunction with the IPO and to estimate interest expense related to the 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.

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, LLC, a wholly owned subsidiary of QEP Field Services, from QEP Field Services for $230.0 million. The Green River Processing Acquisition is accounted for as an equity investment in an unconsolidated affiliate and is not reflected in prior year results. For the three months ended September 30, 2014, Green River Processing net income attributable to QEPM was $5.5 million.

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.


25



 
 
 
 
Three Months Ended September 30, 2013
 

Three Months Ended September 30, 2014

Period from August 14, 2013 to September 30, 2013

Period from July 1, 2013 to August 13, 2013
 
 
 
 
 
 

Successor

Successor

Predecessor as reported

Pro Forma Adjustments(1)
 

Pro Forma
 

(in millions, except operating and per unit amounts)
Revenues

 
 
 
 



 

 
Gathering and transportation

$
28.6

 
$
16.2

 
$
19.2


$
(3.9
)
 

$
31.5

Condensate sales

0.1

 
0.2

 
0.9


0.1

 

1.2

Total revenues

28.7

 
16.4

 
20.1


(3.8
)
 

32.7

Operating expenses

 
 
 
 
 

 
 

 
Gathering expense

5.8

 
3.1

 
3.7


(1.0
)
 

5.8

General and administrative

4.1

 
1.5

 
3.2


(0.9
)
(2) 

3.8

Taxes other than income taxes

0.5

 
0.3

 
0.4


(0.1
)
 

0.6

Depreciation and amortization

8.0

 
4.1

 
4.9


(0.6
)
 

8.4

Total operating expenses

18.4

 
9.0

 
12.2


(2.6
)
 

18.6

Net loss from property sales


 

 
(0.1
)


 

(0.1
)
Operating income

10.3

 
7.4

 
7.8


(1.2
)
 

14.0

Income from unconsolidated affiliates

5.9

 

 
0.4


(0.3
)
 

0.1

Interest expense

(1.5
)
 
(0.3
)
 
(0.5
)

0.4

(3) 

(0.4
)
Net income

14.7

 
7.1

 
7.7


(1.1
)
 

13.7

Net income attributable to noncontrolling interest

(1.0
)
 
(0.6
)
 
(0.6
)


 

(1.2
)
Net income attributable to QEP Midstream or Predecessor

$
13.7

 
$
6.5

 
$
7.1


$
(1.1
)
 

$
12.5

Operating Statistics

 


 



 

 
Natural gas throughput in millions of MMBtu

 


 



 

 
Gathering and transportation

71.2


40.8

 
45.9


(8.9
)
 

77.8

Equity interest (4)

5.3


2.5

 
2.8


(1.9
)
 

3.4

Total natural gas throughput

76.5


43.3

 
48.7


(10.8
)
 

81.2

Throughput attributable to noncontrolling interests(5)

(2.9
)

(0.8
)
 
(1.4
)


 

(2.2
)
Total throughput attributable to QEP Midstream or Predecessor

73.6


42.5

 
47.3


(10.8
)
 

79.0

Crude oil and condensate gathering system throughput volumes (in MBbls)

1,108.8


670.3

 
583.4



 

1,253.7

Water gathering volumes (in MBbls)

1,344.1


538.4

 
552.6



 

1,091.0

Condensate sales volumes (in MBbls)

1.0


2.2

 
11.7


0.9

 

14.8

Price

 


 
 

 
 

 
Average gas gathering and transportation fee (per MMBtu)

$
0.33


$
0.34

 
$
0.37


 
 

$
0.34

Average oil and condensate gathering fee (per barrel)

$
2.21


$
2.34

 
$
2.37


 
 

$
2.35

Average water gathering fee (per barrel)

$
1.87


$
1.85

 
$
1.83


 
 

$
1.84

Average condensate sale price (per barrel)

$
85.25


$
85.25

 
$
78.79


 
 

$
80.05

Non-GAAP Measures

 


 
 

 
 


Adjusted EBITDA (6)

$
23.6


$
10.7

 
$
12.6


$
(2.1
)
 

$
21.2

Distributable Cash Flow (6)
 
$
18.6

 
$
9.8

 
 
 
 
 
 
 

(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 includes amortization of deferred finance cost and commitment fees on the unused portion of the Credit Facility.

26



(4) 
For Successor periods, includes our 50% share of gross volumes from Three Rivers Gathering. For Predecessor periods, includes our 50% share of gross volumes from Three Rivers Gathering and our Predecessor's 38% share of gross volumes from Uintah Basin Field Services.
(5) 
Includes the 22% noncontrolling interest in Rendezvous Gas.
(6) 
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “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.

27



 
 
 
 
Nine Months Ended September 30, 2013
 
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013 to September 30, 2013
 
Period from January 1, 2013 to August 13, 2013
 
 
 
 
 
 
 
Successor
 
Successor
 
Predecessor As Reported
 
Pro Forma Adjustments (1)
 
 
Pro Forma
 
 
(in millions, except operating and per unit amounts)
Revenues
 
 
 
 
 
 
 
 
 
 
 
Gathering and transportation
 
$
85.9

 
$
16.2

 
$
92.9

 
$
(19.9
)
 
 
$
89.2

Condensate sales
 
4.0

 
0.2

 
7.4

 
(1.8
)
 
 
5.8

Total revenues
 
89.9

 
16.4

 
100.3

 
(21.7
)
 
 
95.0

Operating expenses
 
 
 
 
 
 
 
 
 
 

Gathering expense
 
17.6

 
3.1

 
19.7

 
(5.4
)
 
 
17.4

General and administrative
 
14.0

 
1.5

 
13.6

 
(2.7
)
(2) 
 
12.4

Taxes other than income taxes
 
1.5

 
0.3

 
1.3

 
(0.5
)
 
 
1.1

Depreciation and amortization
 
24.0

 
4.1

 
25.0

 
(5.7
)

 
23.4

Total operating expenses
 
57.1

 
9.0

 
59.6

 
(14.3
)
 
 
54.3

Net loss from property sales
 

 

 
(0.5
)
 
0.4

 
 
(0.1
)
Operating income
 
32.8

 
7.4

 
40.2

 
(7.0
)
 
 
40.6

Income from unconsolidated affiliates
 
7.8

 

 
3.8

 
(2.2
)
 
 
1.6

Interest expense
 
(2.6
)
 
(0.3
)
 
(2.6
)
 
1.4

(3) 
 
(1.5
)
Net income
 
38.0

 
7.1

 
41.4

 
(7.8
)
 
 
40.7

Net income attributable to noncontrolling interest
 
(2.7
)
 
(0.6
)
 
(2.5
)
 

 
 
(3.1
)
Net income attributable to QEP Midstream or Predecessor
 
$
35.3

 
$
6.5

 
$
38.9

 
$
(7.8
)
 
 
$
37.6

Operating Statistics
 
 
 

 
 
 
 
 
 

Natural gas throughput in millions of MMBtu
 
 
 

 
 
 
 
 
 

Gathering and transportation
 
216.8

 
40.8

 
230.9

 
(45.8
)
 
 
225.9

Equity interest (4)
 
15.9

 
2.5

 
13.4

 
(2.8
)
 
 
13.1

Total natural gas throughput
 
232.7

 
43.3

 
244.3

 
(48.6
)
 
 
239.0

Throughput attributable to noncontrolling interests(5)
 
(8.2
)
 
(0.8
)
 
(6.7
)
 

 
 
(7.5
)
Total throughput attributable to QEP Midstream or Predecessor
 
224.5

 
42.5

 
237.6

 
(48.6
)
 
 
231.5

Crude oil and condensate gathering system throughput volumes (in MBbls)
 
3,290.9

 
670.3

 
3,243.1

 

 
 
3,913.4

Water gathering volumes (in MBbls)
 
3,594.2

 
538.4

 
2,450.3

 

 
 
2,988.7

Condensate sales volumes (in MBbls)
 
46.9

 
2.2

 
90.6

 
(21.8
)
 
 
71.0

Price
 
 
 

 
 
 
 
 
 

Average gas gathering and transportation fee (per MMBtu)
 
$
0.32

 
$
0.34

 
$
0.35

 


 
 
$
0.33

Average oil and condensate gathering fee (per barrel)
 
$
2.32

 
$
2.34

 
$
2.44

 


 
 
$
2.42

Average water gathering fee (per barrel)
 
$
1.86

 
$
1.85

 
$
1.82

 


 
 
$
1.82

Average condensate sale price (per barrel)
 
$
85.25

 
$
85.25

 
$
81.63

 


 
 
$
81.90

Non-GAAP Measures
 
 
 

 
 
 
 
 
 

Adjusted EBITDA (6)
 
$
61.7

 
$
10.7

 
$
66.7

 
$
(15.3
)
 
 
$
62.1

Distributable Cash Flow (6)
 
$
52.0

 
$
9.8

 
 
 
 
 
 
 

(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 includes amortization of deferred finance cost and commitment fees on the unused portion of the Credit Facility.

28



(4) 
For Successor periods, includes our 50% share of gross volumes from Three Rivers Gathering. For Predecessor periods, includes our 50% share of gross volumes from Three Rivers Gathering and our Predecessor's 38% share of gross volumes from Uintah Basin Field Services.
(5) 
Includes the 22% noncontrolling interest in Rendezvous Gas.
(6) 
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. See “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 nine months ended September 30, 2014, are presented below.

Three Months Ended September 30, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $28.6 million for the three months ended September 30, 2014.

Natural gas gathering and transportation revenue was $23.7 million for the three months ended September 30, 2014, with throughput of 73.6 MMBtu and an average gas gathering and transportation fee of $0.33 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 51.7 MMBtu of throughput, and our Vermillion Gathering System, which contributed throughput of 8.5 MMBtu.

Crude oil and condensate gathering revenue was $2.4 million for the three months ended September 30, 2014. The average gathering fee was $2.21 per barrel and throughput was 1,108.8 MBbls of which 869.9 MBbls were attributable to our Green River Gathering System and 238.9 MBbls were attributable to our Williston Gathering System.

Water gathering revenue was $2.5 million for the three months ended September 30, 2014, with throughput of 1,344.1 MBbls and an average fee of $1.87 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $0.1 million for the three months ended September 30, 2014. Sales volumes were 1.0 MBbl 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 $5.8 million for the three months ended September 30, 2014, the majority of which was incurred on our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $4.1 million for the three months ended September 30, 2014, consisting of $3.5 million of charges under the Omnibus Agreement, $0.1 million of equity-based compensation expense, $0.3 million of professional services fees incurred for the Green River Processing Acquisition, and $0.2 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 September 30, 2014, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $8.0 million for the three months ended September 30, 2014.


29



Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $5.9 million for the three months ended September 30, 2014, related to $5.5 million of income from our 40% interest in Green River Processing, acquired July 1, 2014, and $0.4 million of income from our 50% interest in Three Rivers Gathering.

Interest expense. Interest expense was $1.5 million for the three months ended September 30, 2014, which consisted of $1.1 million related to interest expense on the outstanding balance on the Credit Facility, $0.2 million related to commitment fees paid on the unused portion of the Credit Facility and $0.2 million related to the amortization of debt issuance costs.

Nine Months Ended September 30, 2014 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $85.9 million for the nine months ended September 30, 2014.

Natural gas gathering and transportation revenue was $68.8 million for the nine months ended September 30, 2014, with throughput of 224.5 MMBtu and an average gas gathering and transportation fee of $0.32 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 149.0 MMBtu of throughput, and our Vermillion Gathering System, which contributed throughput of 30.1 MMBtu.

Crude oil and condensate gathering revenue was $7.6 million for the nine months ended September 30, 2014. The average gathering fee was $2.32 per barrel and throughput was 3,290.9 MBbls of which 2,524.1 MBbls were attributable to our Green River Gathering System and 766.8 MBbls were attributable to our Williston Gathering System.

Water gathering revenue was $6.7 million for the nine months ended September 30, 2014, with throughput of 3,594.2 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 nine months ended September 30, 2014, related to deficiency revenue of $2.8 million, all of which was attributable to our Williston Gathering System.

Condensate sales. Revenue from condensate sales was $4.0 million for the nine months ended September 30, 2014. Sales volumes were 46.9 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 $17.6 million for the nine months ended September 30, 2014, the majority of which was incurred on our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $14.0 million for the nine months ended September 30, 2014, consisting of $10.4 million of charges under the Omnibus Agreement, $0.7 million of equity-based compensation expense, $1.4 million of professional services fees incurred for the Green River Processing Acquisition, and $1.5 million of expenses related to operating as a publicly traded partnership.

Taxes other than income taxes. Taxes other than income taxes were $1.5 million for the nine months ended September 30, 2014, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $24.0 million for the nine months ended September 30, 2014.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $7.8 million for the nine months ended September 30, 2014, related to $5.5 million income from Green River Processing and $2.3 million income from Three Rivers Gathering.


30



Interest expense. Interest expense was $2.6 million for the nine months ended September 30, 2014, which consisted of $1.1 million related to interest expense on the outstanding balance on the Credit Facility, $1.0 million related to commitment fees paid on the unused portion of the Credit Facility and $0.5 million related to the amortization of debt issuance costs.

Period from August 14, 2013, through September 30, 2013 - Successor

Revenue

Gathering and transportation. Gathering and transportation revenues were $16.2 million for the period from August 14, 2013, through September 30, 2013.

Natural gas gathering and transportation revenue was $13.7 million for the period from August 14, 2013, through September 30, 2013, with throughput of 42.5 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 30.9 MMBtu of throughput as a result of increased production at QEP's Pinedale operations, and our Vermillion Gathering System, which contributed throughput of 6.1 MMBtu.

Crude oil and condensate gathering revenue was $1.5 million for the period from August 14, 2013, through September 30, 2013. The average gathering fee was $2.34 per barrel and throughput was 670.3 MBbls of which 514.9 MBbls were attributable to our Green River Gathering System and 155.4 MBbls were attributable to our Williston Gathering System.

Water gathering revenue was $1.0 million for the period from August 14, 2013, through September 30, 2013, with throughput of 538.4 MBbls and an average fee of $1.85 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $0.2 million for the period from August 14, 2013, through September 30, 2013. Sales volumes were 2.2 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 $3.1 million for the period from August 14, 2013, through September 30, 2013, the majority of which was incurred on our Green River and Vermillion Gathering systems.

General and administrative. General and administrative expenses were $1.5 million for the period from August 14, 2013, through September 30, 2013, consisting of $1.2 million of charges under the Omnibus Agreement, $0.1 million of equity-based compensation expense and the remainder related to other expenses related to operating as a publicly traded partnership.

Taxes other than income taxes. Taxes other than income taxes were $0.3 million for the period from August 14, 2013, through September 30, 2013, primarily attributable to property tax expense on our gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $4.1 million for the period from August 14, 2013, through September 30, 2013.

Other Results Below Operating Income

Interest expense. Interest expense was $0.3 million for the period from August 14, 2013, through September 30, 2013, related to commitment fees paid on the unused portion of the Credit Facility. There were no borrowings under the credit facility during the period.




31



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.

Period from July 1, 2013, through August 13, 2013 - Predecessor

Revenue

Gathering and transportation. Gathering and transportation revenues were $19.2 million for the period from July 1, 2013, through August 13, 2013.

Natural gas gathering and transportation revenue was $16.8 million for the period from July 1, 2013, through August 13, 2013, with throughput of 47.3 MMBtu and an average gas gathering and transportation fee of $0.37 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System which contributed 25.4 MMBtu of throughput; the Predecessor's Uinta Basin Gathering System with throughput of 8.9 MMBtu; and our Vermillion Gathering System with throughput of 5.1 MMBtu.

Crude oil and condensate gathering revenue was $1.4 million for the period from July 1, 2013 through August 13, 2013, as a result of an average gathering fee of $2.37 per barrel and throughput of 583.4 MBbls of which 462.6 MBbls were attributable to our Green River Gathering System and 120.8 MBbls were attributable to our Williston Gathering System.

Water gathering revenue consisted of $1.0 million for the period from July 1, 2013 through August 13, 2013, from throughput of 552.6 MBbls and an average fee of $1.83 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $0.9 million for the period from July 1, 2013, through August 13, 2013, from sales volumes of 11.7 MBbls at a price of $78.79 per barrel, primarily attributable to our Green River Gathering System.
Operating Expenses

Gathering expense. Gathering expense was $3.7 million for the period from July 1, 2013, through August 13, 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 $3.2 million for the period from July 1, 2013, through August 13, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

Taxes other than income taxes. Taxes other than income taxes were $0.4 million for the period from July 1, 2013, through August 13, 2013, primarily attributable to property tax expense on the gathering systems.

Depreciation and amortization. Depreciation and amortization expenses were $4.9 million for the period from July 1, 2013, through August 13, 2013.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates was $0.4 million for the period from July 1, 2013, through August 13, 2013. Of the $0.4 million, income from the Predecessor's ownership in Uintah Basin Field Services was $0.3 million and income from our ownership in Three Rivers Gathering was $0.1 million.

Interest expense. Interest expense was $0.5 million for the period from July 1, 2013, through August 13, 2013, related to interest charged on the Predecessor's outstanding long-term debt with QEP during the period.


32



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

Revenue

Gathering and transportation. Gathering and transportation revenues were $92.9 million for the period from January 1, 2013, through August 13, 2013.

Natural gas gathering and transportation revenue was $80.7 million for the period from January 1, 2013, through August 13, 2013, with throughput of 237.6 MMBtu and an average gas gathering and transportation fee of $0.35 per MMBtu. The majority of the natural gas throughput was attributable to our Green River Gathering System, which contributed 124.0 MMBtu of throughput; the Predecessor's Uinta Basin Gathering System, with throughput of 45.8 MMBtu; and our Vermillion Gathering System, with throughput of 30.2 MMBtu.

Crude oil and condensate gathering revenue was $7.8 million for the period from January 1, 2013, through August 13, 2013, as a result of an average gathering fee of $2.44 per barrel and throughput of 3,243.1 MBbls of which 2,490.0 MBbls were attributable to our Green River Gathering System and 753.1 MBbls were attributable to our Williston Gathering System.

Water gathering revenue consisted of $4.4 million for the period from January 1, 2013, through August 13, 2013, from throughput of 2,450.3 MBbls and an average fee of $1.82 per barrel at our Green River Gathering System.

Condensate sales. Revenue from condensate sales was $7.4 million for the period from January 1, 2013, through August 13, 2013, from sales volumes of 90.6 MBbls at a price of $81.63 per barrel, all of which was attributable to our Green River and Vermillion gathering systems and the Predecessor's Uinta Gathering System.
Operating Expenses

Gathering expense. Gathering expense was $19.7 million for the period from January 1, 2013, through August 13, 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 $13.6 million for the period from January 1, 2013, through August 13, 2013, from the allocation of costs by QEP for various business and corporate services and compensation related expenses.

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

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

Other Results Below Operating Income

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

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


33



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 nine months ended September 30, 2013, on a pro forma basis.

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

Revenue

Gathering and transportation. Gathering and transportation revenues decreased by $2.9 million during the three months ended September 30, 2014, compared to the pro forma three months ended September 30, 2013.

Natural gas gathering and transportation revenues decreased $2.9 million, as a result of a 7% lower gas gathering throughput, and a 3% lower average gathering fee. The decrease in gas gathering throughput is primarily attributable to a 2.7 MMBtu decrease at the Vermillion Gathering System due to reduced drilling activities in that area, and a 3.9 MMBtu decrease at the Green River Gathering System. The decrease in average gas gathering fee is primarily attributable to an decrease in volumes gathered from customers with higher gathering fees.

Crude oil and condensate gathering revenue decreased by $0.5 million during the three months ended September 30, 2014 compared to the pro forma three months ended September 30, 2013, due to a 12% decrease in gathering volumes, primarily at the Green River Gathering System, and a 6% decrease in average gathering fee due to a decrease in volumes gathered from customers with higher average gathering fees. The decrease in gathering volumes is due to lower volumes gathered from producers in this area.

Water gathering revenue increased by $0.5 million, or 26%, due to a 23% increase in gathering volume and a 2% rate escalation on the Green River Gathering System.

Condensate sales. Condensate sales decreased by $1.1 million during the three months ended September 30, 2014, compared to the pro forma three months ended September 30, 2013, due to a 93% decrease in sales volumes primarily attributable to a decrease at the Green River Gathering System, partially offset by a 6% increase in average gathering fee as a result of our fixed-price sales agreement with QEP. Condensate sales variability is due in part to the timing of condensate deliveries to our customers and seasonal variability, as warmer ground temperatures in late summer result in lower condensate recoveries.

Operating Expenses

Gathering expense. Gathering expense was unchanged during the three months ended September 30, 2014, compared to the pro forma three months ended September 30, 2013.

General and administrative. General and administrative expenses for the three months ended September 30, 2014, increased by $0.3 million, or 8%, compared to the pro forma three months ended September 30, 2013, due to professional service fees incurred for the Green River Processing Acquisition.

Taxes other than income taxes. Taxes other than income taxes decreased by $0.1 million during the three months ended September 30, 2014, compared to the pro forma three months ended September 30, 2013, due to lower property taxes at our Green River and Vermillion Gathering systems.

Other Results Below Operating Income

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased by $5.8 million during the three months ended September 30, 2014, compared to the pro forma three months ended September 30, 2013, primarily due to $5.5 million in income recognized from the Green River Processing Acquisition, which occurred on July 1, 2014. The remaining increase is attributable to our ownership in Three Rivers Gathering.

34




Interest expense. Interest expense during the three months ended September 30, 2014, increased $1.1 million compared to the pro forma three months ended September 30, 2013, due to borrowings under the Credit Facility for the Green River Processing Acquisition which closed on July 1, 2014.


Supplemental Pro Forma Analysis - Successor Nine Months Ended September 30, 2014, Compared to Pro Forma Nine Months Ended September 30, 2013

Revenue

Gathering and transportation. Gathering and transportation revenues decreased by $3.3 million during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 30, 2013.

Natural gas gathering and transportation revenues decreased $5.1 million, as a result of lower gas gathering throughput of 7.0 MMBtu and a 3% lower average gas gathering fee. The decrease in throughput was primarily attributable to a 6.2 MMBtu decrease at the Vermillion Gathering System due to reduced drilling activities in that area, and a 3.0 MMBtu decrease at the Green River Gathering System.

Crude oil and condensate gathering revenue was $0.9 million lower during the nine months ended September 30, 2014 compared to the pro forma nine months ended September 30, 2013, due to a 16% decrease in gathering volume, partially offset by a 4% increase in average gathering fees. The decrease in throughput was primarily attributable to 0.5 MBbls decrease at the Green River Gathering System and 0.1 MBbls decrease at the Williston Gathering System.

Water gathering revenue increased by $1.2 million, or 23%, due to a 20% increase in gathering volume and a 2% rate escalation at the Green River Gathering System.

Deficiency revenue increased by $1.5 million during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 30, 2013, due to higher deficiency revenue attributable to the Williston Gathering System.

Condensate sales. Condensate sales decreased by $1.8 million during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 30, 2013, due to a 34% decrease in sales volumes, partially offset by a 4% increase in average gathering fees as a result of our fixed-price sales agreement with QEP. The decrease in sales volumes is attributable to a 65% decrease in volumes at the Green River Gathering System, partially offset by an 8% increase at the Vermillion Gathering System. Condensate sales variability is due in part to the timing of condensate deliveries to our customers and seasonal variability, as warmer ground temperatures in late summer result in lower condensate recoveries.

Operating Expenses

Gathering expense. Gathering expense increased by $0.2 million, or 1%, during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 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 nine months ended September 30, 2014, increased by $1.6 million, or 13%, compared to the pro forma nine months ended September 30, 2013, primarily due to professional service fees incurred for the Green River Processing Acquisition.

Taxes other than income taxes. Taxes other than income taxes increased by $0.4 million during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 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 $6.2 million during the nine months ended September 30, 2014, compared to the pro forma nine months ended September 30, 2013, primarily due to $5.5 million income recognized from the Green River Processing Acquisition, which occurred on July 1, 2014. The remaining increase is attributable to our ownership in Three Rivers Gathering.


35



Interest expense. Interest expense during the nine months ended September 30, 2014, increased $1.1 million compared to the pro forma nine months ended September 30, 2013, due to borrowings under the Credit Facility for the Green River Processing Acquisition which closed on July 1, 2014.


36



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.

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. The following tables present unaudited reconciliations of Adjusted EBITDA and Distributable Cash Flow to net income attributable to the Partnership or the Predecessor, as applicable, and net cash provided by operating activities for each of the periods indicated.



Three Months Ended September 30, 2013



Nine Months Ended September 30, 2013
 
Three Months Ended September 30, 2014

Period from August 14, 2013, through September 30, 2013

Period from July 1, 2013, through August 13, 2013

Nine Months Ended September 30, 2014

Period from August 14, 2013, through September 30, 2013

Period from January 1, 2013, through August 13, 2013
 
Successor

Successor

Predecessor

Successor

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
$
13.7


$
6.5


$
7.1

 
$
35.3


$
6.5


$
38.9

Interest expense
1.5


0.3


0.5

 
2.6


0.3


2.6

Depreciation and amortization
8.0


4.1


4.9

 
24.0


4.1


25.0

Noncontrolling interest share of depreciation and amortization(1)
(0.7
)

(0.4
)

(0.3
)
 
(2.0
)

(0.4
)

(1.6
)
QEP Midstream share of unconsolidated affiliate depreciation and amortization (2)
1.1


0.2


0.3

 
1.8


0.2


1.3

Net loss from property sales




0.1

 




0.5

Adjusted EBITDA
$
23.6


$
10.7


$
12.6

 
$
61.7


$
10.7


$
66.7

Net cash interest paid
(1.3
)

(0.2
)


 
(2.1
)

(0.2
)


Maintenance capital expenditures
(3.3
)

(4.3
)


 
(10.6
)

(4.3
)


Reimbursements for maintenance capital expenditures


3.0



 
1.0


3.0



Cash adjustments related to equity method investments and non-controlling interest
(0.6
)

0.6



 
1.5


0.6



Non-cash equity-based compensation expense
0.2





 
0.5





Distributable Cash Flow
$
18.6


$
9.8



 
$
52.0


$
9.8



        
(1) 
Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services.
(2) 
Represents QEP Midstream's share of Three Rivers Gathering and Green River Processing depreciation and amortization. For the three months ended September 30, 2014, $0.3 million was attributable to Three Rivers Gathering and $0.8 million was attributable to Green River Processing. For the nine months ended September 30, 2014, $1.0 million was attributable to Three Rivers Gathering and $0.8 million was attributable to Green River Processing. For the period from August 14, 2013, through September 30, 2013, and for the period from January 1, 2013, through August 13, 2013, all unconsolidated affiliate depreciation and amortization is related to Three Rivers Gathering.




37



 
 


Nine Months Ended September 30, 2013
 
 
Nine Months Ended September 30, 2014

Period from August 14, 2013, through September 30, 2013

Period from January 1, 2013, through August 13, 2013
 
 
Successor

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
 
$
56.8


$
13.8


$
89.8

Noncontrolling interest share of depreciation and amortization(1)
 
(2.0
)

(0.4
)

(1.6
)
QEP Midstream share of unconsolidated affiliate depreciation and amortization(2)
 
1.8


0.2


1.3

Income from unconsolidated affiliates, net of distributions from unconsolidated affiliates
 
1.3





Net income attributable to noncontrolling interest
 
(2.7
)

(0.6
)

(2.5
)
Interest expense
 
2.6


0.3


2.6

Working capital changes
 
5.1


(2.4
)

(22.9
)
Amortization of deferred financing charges
 
(0.5
)

(0.1
)


Equity-based compensation expense
 
(0.7
)

(0.1
)


Adjusted EBITDA
 
$
61.7


$
10.7


$
66.7

Net cash interest paid
 
(2.1
)

(0.2
)


Maintenance capital expenditures
 
(10.6
)

(4.3
)


Reimbursements for maintenance capital expenditures
 
1.0


3.0



Cash adjustments related to equity method investments and non-controlling interest
 
1.5


0.6



Non-cash equity-based compensation expense
 
0.5





Distributable Cash Flow
 
$
52.0


$
9.8




        
(1)
Represents the noncontrolling interest's 22% share of depreciation and amortization attributable to Rendezvous Gas Services.
(2) 
Represents QEP Midstream's share of Three Rivers Gathering and Green River Processing depreciation and amortization. For the nine months ended September 30, 2014, $1.0 million was attributable to Three Rivers Gathering and $0.8 million was attributable to Green River Processing. For the period from August 14, 2013, through September 30, 2013, and for the period from January 1, 2013, through August 13, 2013, all unconsolidated affiliate depreciation and amortization is related to Three Rivers Gathering.


38



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.
 
 
 
 
Nine Months Ended September 30, 2013
 
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013, through September 30, 2013

Period from January 1, 2013, through August 13, 2013
 
 
Successor
 
Successor
 
Predecessor
 
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
 
Operating activities
 
$
56.8

 
$
13.8

 
$
89.8

Investing activities
 
$
(119.5
)
 
$
(1.8
)
 
$
(7.4
)
Financing activities
 
$
59.1

 
$
2.8

 
$
(82.7
)

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:
 
 
 
 
Nine Months Ended September 30, 2013
 
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013, through September 30, 2013

Period from January 1, 2013, through August 13, 2013
 
 
Successor
 
Successor

Predecessor
 
(in millions)
Net income
 
$
38.0

 
$
7.1

 
$
41.4

Non-cash adjustments to net income
 
23.9

 
4.3

 
25.5

Changes in operating assets and liabilities
 
(5.1
)
 
2.4

 
22.9

Net cash provided by operating activities
 
$
56.8

 
$
13.8

 
$
89.8



39



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 and borrowings under the Credit Facility. Capital expenditures for the nine months ended September 30, 2014 and for the periods from August 14, 2013, through September 30, 2013 and January 1, 2013, through August 13, 2013 are presented in the following table:
 
 
 
 
Nine Months Ended September 30, 2013
 
 
Nine Months Ended September 30, 2014
 
Period from August 14, 2013, through September 30, 2013
 
Period from January 1, 2013, through August 13, 2013
 
 
Successor
 
Successor
 
Predecessor
 
(in millions)
Total accrued capital expenditures
 
$
11.6

 
$
4.7

 
$
7.5

Change in accruals and non-cash items
 
2.8

 
(2.5
)
 
1.6

Total cash capital expenditures
 
$
14.4

 
$
2.2

 
$
9.1


In addition to the capital expenditures noted above, the Partnership acquired 40% of the membership interests in Green River Processing for $230.0 million. The cash flow statement amount of $106.9 million of cash investing outflows is due to the transaction being accounted for as entities under common control. The Partnership also made contributions to Green River Processing of $1.1 million, of which $0.7 million was capital expenditures related to various system maintenance projects and $0.4 million was for an operating expense reserve. Additionally, the Partnership had distributions from equity investments in excess of cumulative earnings of $2.9 million from its investment in Three Rivers Gathering.

Financing Activities. For the nine months ended September 30, 2014, the Partnership's cash generated from financing activities consisted of $230.0 million net borrowings from the Credit Facility, $44.2 million in unitholder distributions paid in February 2014, May 2014 and August 2014, and $4.6 million in distributions to its noncontrolling interest in Rendezvous Gas. Additionally, the Partnership had cash contributions of $123.1 million equal to the amount of the Green River Processing Acquisition purchase price in excess of the carrying value of assets acquired.

As a result of the IPO, for the period from August 14, 2013, through September 30, 2013, we had net proceeds of $449.6 million which were used to repay long-term debt to QEP of $95.5 million, pay revolving credit origination fees of $3.0 million and make a cash distribution to QEP of $351.1 million. Additionally during that period, the Partnership received $3.0 million from QEP under the indemnification provisions of the Omnibus Agreement for capital expenditures incurred by the Partnership for a pipeline repair project.
    
For the period from January 1, 2013, through August 13, 2013, the Predecessor's cash used in financing activities primarily consisted of $66.4 million in repayments of long-term debt to QEP. In addition, the Predecessor made distributions to QEP of $12.2 million and paid distributions to its noncontrolling interest in Rendezvous Gas of $4.1 million for the period from January 1, 2013, through September 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

40



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 $11.6 million for the Partnership for the nine months ended September 30, 2014, which includes maintenance capital of $10.6 million and expansion capital of $1.0 million. Maintenance capital expenditures of $10.6 million included $8.0 million related to the Green River Gathering System, of which $3.2 million related to a compressor maintenance overhaul project, $3.7 million related to system maintenance, and $1.1 million related to a condensate pipeline repair and replacement project. The Partnership was reimbursed by QEP for the $1.1 million of pipeline repair costs pursuant to an indemnification provision in the Omnibus Agreement. The remaining maintenance capital expenditures of $2.6 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 $13.0 million to $16.0 million for the year ending December 31, 2014. This amount includes approximately $12.0 million to $14.0 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 $3.0 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 was paid on August 14, 2014, to unitholders of record as of the close of business on August 4, 2014.

On October 22, 2014, the Partnership declared a quarterly cash distribution totaling $16.4 million, or $0.30 per unit for the third quarter of 2014. The quarterly distribution will be paid on November 14, 2014, to unitholders of record as of the close of business on November 4, 2014.

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

41



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.

As of September 30, 2014, there was $230.0 million outstanding under the Credit Facility, and the Partnership was in compliance with the covenants under the credit agreement. During the nine months ended September 30, 2014, QEP Midstream's weighted average interest rate on borrowings was 1.94%. The unused portion of the Credit Facility is subject to a commitment fee ranging from 0.325% to 0.500% per annum. In October 2014, QEP, through its wholly owned subsidiary, QEP Field Services, entered into a definitive agreement to sell its midstream business to Tesoro Logistics LP in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance the Partnership's debt.

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 nine months ended September 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 September 30, 2014, the Partnership has deferred revenue of $13.2 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 10 - 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.


42



Related Parties

Our General Partner is owned by QEP Field Services, which is a subsidiary of QEP. As of September 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 1,090,495 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 nine months ended September 30, 2014, approximately 68% and 69%, respectively, of our revenue came from QEP. During the period from August 14, 2013 to September 30, 2013, approximately 68% of our revenue came from QEP. Prior to the IPO, the Predecessor had other agreements in place with QEP resulting in related party transactions. For the period from July 1, 2013 to August 13, 2013, QEP accounted for approximately 60% of the Predecessor's total revenue. For the period from January 1, 2013 to August 13, 2013, QEP accounted for approximately 53% of the Predecessor's total revenue. Refer to Note 5 - 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 nine months ended September 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 April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The ASU currently has no impact on the Partnership's consolidated financial statements as no divestitures have occurred.

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.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Partnership is currently evaluating the impact of this standard on its financial statements and does not believe there will be a material impact.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

The Partnership's Credit Facility contains a variable interest rate that exposes us to volatility in interest rates. At September 30, 2014, the Partnership had $230.0 million outstanding under the Credit Facility. If interest rates had increased or decreased 10% over the nine months ended September 30, 2014, at our average level of borrowing for those same periods, our interest expense would have increased or decreased by $0.1 million for the nine months ended September 30, 2014.

Commodity Price Risk

We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenues is dependent upon the price received for the condensate. Condensate historically sells at a 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, we 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.

With our Green River Processing Acquisition, a portion of our profitability is directly affected by prevailing commodity prices related to keep-whole processing contracts. In these contracts, operating margin is determined by, in large part, the spread between NGL product sales price and the purchase price of natural gas. Generally, the frac spread and, consequently, the net operating margins, are positive under these contracts. However, in the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer "whole" could result in operating losses from our ownership in Green River Processing. Certain of these keep-whole processing contracts contain provisions that allow Green River Processing to charge an incremental fee in the event that processing gas under the contract becomes unprofitable. On occasion, we enter into derivative transactions to manage commodity price risk.

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:

timing of the closing of QEP Field Services sale of its midstream business, including its ownership in the Partnership, to Tesoro;
impact of recent accounting developments;
belief that the historical financial results of our Predecessor are not indicative of actual results of operation of our Predecessor as a standalone entity and our future results;
favorable terms of related party agreements;
fees charged for firm service and the steadiness of revenues from fee-based agreements;
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;

44



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;
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;
maintenance of controls before and after the implementation by QEP of the new ERP system;
exposure to commodity price risks; and
estimated amounts and timing of distributions.

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

45



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.

46



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 September 30, 2014. Based on such evaluation, our management has concluded that, as of September 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 believes that QEP and the Partnership 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. The Partnership believes it will meet the required implementation date for the 2013 Framework 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.



47



PART II. OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth under Litigation in "Note 10 - Commitments and Contingencies" to the Partnership's unaudited condensed 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. With the Green River Processing Acquisition, we expanded our operations to include the processing and treating of natural gas and the fractionation and transportation of NGL. As a result, we have expanded our risk factors to reference the risks related to such operations. Except for the risk factors set forth below, there are no material changes to the risk factors included in our Form 10-K.

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

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

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

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

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

48



on our systems for additional volumes, we may not be able to compete effectively with third-party systems for additional oil and natural gas production in our areas of operation.

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

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

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

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

If a customer’s actual throughput volumes or volumes processed are less than its minimum volume commitment for the applicable period, it must make a deficiency payment to us at the end of that contract year or the term of the minimum volume commitment, as applicable. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering or processing fee. To the extent that a customer’s actual throughput volumes or volumes processed are above or below its minimum volume commitment for the applicable period, several of our gathering and processing agreements with minimum volume commitments contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments in subsequent periods.

These provisions include the following:
To the extent that a customer’s throughput volumes or volumes processed are less than its minimum volume commitment for the applicable period and the customer makes a deficiency payment, it is entitled to an offset in one or more subsequent periods to the extent that its volumes in subsequent periods exceed its minimum volume commitment for those periods. In such a situation, we would not receive gathering or processing fees on volumes in excess of a customer’s applicable minimum volume commitment (depending on the terms of the specific gathering or processing agreement) to the extent that the customer had made a deficiency payment with respect to one or more preceding years.
To the extent that a customer’s throughput volumes or volumes processed exceed its minimum volume commitment in the applicable period, it is entitled to apply the excess volumes against its aggregate minimum volume commitment, thereby reducing the period for which its annual minimum volume commitment applies. For example, one of our customers has a contracted minimum volume commitment term from December 2007 through December 2017.

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Should this customer continually ship volumes in excess of its minimum volume commitment, the average remaining period for which our minimum volume commitments apply could be less than the average of the original stated terms of our minimum volume commitment.
To the extent that a customer’s throughput volumes or volumes processed exceed its minimum volume commitment for the applicable period, there is a crediting mechanism that allows the customer to build a “bank” of credits that it can utilize in the future to reduce deficiency payments owed in subsequent periods, subject to expiration if there is no deficiency payment owed in subsequent periods. The period over which this credit bank can be applied to future deficiency payments varies, depending on the particular gathering or processing agreement.

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

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

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

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

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

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reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners or operators of our assets, pursuant to any indemnification rights, for potential environmental liabilities.

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

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

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

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

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

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

The Majority of Our Pipelines Are Not Subject to Regulation By the FERC; However, a Change in the Jurisdictional Characterization of Our Assets, or a Change in Policy, Could Result in Increased Regulation of Our Assets Which Could Materially and Adversely Affect Our Financial Condition, Results of Operations and Cash Flows. A substantial majority of our assets are gas-gathering facilities or interests in gas-gathering facilities. Natural gas gathering facilities are exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938 (NGA). Although the FERC has not made any formal determinations with respect to all of the facilities we consider to be gathering facilities, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by the FERC on a case-by-case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

Our Gathering Systems and Processing, Treating and Fractionation Facilities Are Subject to State Regulation That Could Materially and Adversely Affect Our Operations and Cash Flows. State regulation of gathering facilities and processing, treating and fractionation facilities includes safety and environmental requirements. In addition, several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations or may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our operations and revenues.

We Are Subject to Stringent Environmental Laws and Regulations That May Expose Us to Significant Costs and Liabilities. Our gathering, transportation, processing, treating and fractionation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
the federal Clean Air Act and analogous state laws that restrict emissions of air pollutants from any sources and impose obligations related to pre-construction activities and monitoring and reporting air emissions;
the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
the Oil Pollution Act of 1990 and analogous state laws that establish strict liability for releases of oil into waters of the United States;
the federal Resource Conservation and Recovery Act (RCRA), and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;
the federal Endangered Species Act (ESA) that restricts activities that may affect endangered and threatened species or their habitats; and
the federal Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

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

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authorities, such as the US Environmental Protection Agency, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Refer to Item 1, Environmental Matters, of Part I of our Annual Report on Form 10-K for the year ended December 31, 2013, for more information on the current and ongoing regulations.

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

When we issue additional units, our General Partner has the right, but not the obligation, under the Partnership Agreement to contribute a proportionate amount of capital to the Partnership to maintain a general partner interest equal to that which existed immediately prior to such issuance. On August 14, 2014, in connection with the General Partner's exercise of its right to make capital contributions to maintain its existing 2.0% general partner interest, the Partnership issued 48 general partner units to the General Partner for $1,230. On September 5, 2014, in connection with the General Partner's exercise of its right to make capital contributions to maintain its existing 2.0% general partner interest, the Partnership issued 161 general partner units to General Partner for $4,183. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the "Securities Act"), as they did not involve a public offering.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES
 
None.

ITEM 4.    MINE SAFETY DISCLOSURES
 
None.

ITEM 5.    OTHER INFORMATION
 
None.

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ITEM 6.    EXHIBITS
 
The following exhibits are being filed as part of this report:
 
Exhibit No.
 
Exhibits
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


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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)
 
 
 
November 6, 2014
 
/s/ Charles B. Stanley
 
 
Charles B. Stanley,
 
 
Chairman, President and Chief Executive Officer
 
 
 
November 6, 2014
 
/s/ Richard J. Doleshek
 
 
Richard J. Doleshek,
 
 
Executive Vice President and Chief Financial Officer


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