ANDEAVOR LOGISTICS LP - FORM 10-Q

Attached files

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EX-4.2 - EXHIBIT 4.2 - ANDEAVOR LOGISTICS LP	tllpex426302015.htm
EX-4.1 - EXHIBIT 4.1 - ANDEAVOR LOGISTICS LP	tllpex416302015.htm
EX-4.3 - EXHIBIT 4.3 - ANDEAVOR LOGISTICS LP	tllpex436302015.htm
EX-32.2 - EXHIBIT 32.2 - ANDEAVOR LOGISTICS LP	tllpex3226302015.htm
EX-31.2 - EXHIBIT 31.2 - ANDEAVOR LOGISTICS LP	tllpex3126302015.htm
EX-10.3 - EXHIBIT 10.3 - ANDEAVOR LOGISTICS LP	tllpex1036302015.htm
EX-31.1 - EXHIBIT 31.1 - ANDEAVOR LOGISTICS LP	tllpex3116302015.htm
EX-10.4 - EXHIBIT 10.4 - ANDEAVOR LOGISTICS LP	tllpex1046302015.htm
EX-32.1 - EXHIBIT 32.1 - ANDEAVOR LOGISTICS LP	tllpex3216302015.htm
EX-10.5 - EXHIBIT 10.5 - ANDEAVOR LOGISTICS LP	tllpex1056302015.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

(Mark One)



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

For the quarterly period ended June 30, 2015



¨	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 1‑35143

TESORO LOGISTICS LP

(Exact name of registrant as specified in its charter)



Delaware		27‑4151603
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

19100 Ridgewood Pkwy, San Antonio, Texas 78259-1828
(Address of principal executive offices) (Zip Code)

210-626-6000
(Registrant’s telephone number, including area code)

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 þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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 þ No ¨

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



Large accelerated filer þ	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

There were 88,096,974 common units and 1,631,448 general partner units of the registrant outstanding at August 3, 2015.

TESORO LOGISTICS LP

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

TABLE OF CONTENTS



PART I. FINANCIAL INFORMATION		Page

Item 1.	Financial Statements (Unaudited)	3

	Condensed Statements of Combined Consolidated Operations - Three and Six Months Ended June 30, 2015 and 2014	3

	Condensed Consolidated Balance Sheets - June 30, 2015 and December 31, 2014	4

	Condensed Statements of Combined Consolidated Cash Flows - Six Months Ended June 30, 2015 and 2014	5

	Notes to Condensed Combined Consolidated Financial Statements	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41

Item 4.	Controls and Procedures	42

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 5.	Other Information	43

Item 6.	Exhibits	44

SIGNATURES		45

Non Wholly-Owned Guarantor Subsidiary Financial Statements		F-1

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TESORO LOGISTICS LP

CONDENSED STATEMENTS OF COMBINED CONSOLIDATED OPERATIONS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014 (a)			2015			2014 (a)
	(In millions, except unit and per unit amounts)
Revenues
Affiliate	$	154		$	117		$	302		$	228
Third-party	121			16			236			32
Total Revenues	275			133			538			260
Costs and Expenses
Operating and maintenance expenses	105			63			199			115
Imbalance settlement gains and reimbursements from Tesoro	(11		)	(8		)	(19		)	(15		)
General and administrative expenses	28			13			53			23
Depreciation and amortization expenses	44			17			88			33
Net gain on asset disposals and impairments	—			—			—			(4		)
Total Costs and Expenses	166			85			321			152
Operating Income	109			48			217			108
Interest and financing costs, net	(38		)	(17		)	(75		)	(35		)
Equity in earnings of unconsolidated affiliates	1			—			4			—
Net Income	$	72		$	31		$	146		$	73

Loss attributable to Predecessors	—			3			—			4
Net income attributable to noncontrolling interest	(6		)	—			(16		)	—
Net income attributable to partners	66			34			130			77
General partner’s interest in net income, including incentive distribution rights	(17		)	(8		)	(31		)	(15		)
Limited partners’ interest in net income	$	49		$	26		$	99		$	62

Net income per limited partner unit:
Common - basic	$	0.60		$	0.45		$	1.23		$	1.15
Common - diluted	$	0.60		$	0.45		$	1.23		$	1.14
Subordinated - basic and diluted	$	—		$	0.45		$	—		$	1.13

Weighted average limited partner units outstanding:
Common units - basic	80,742,221			46,911,533			80,497,573			43,070,111
Common units - diluted	80,810,838			47,012,424			80,564,247			43,169,298
Subordinated units - basic and diluted	—			7,543,627			—			11,377,957

Cash distributions paid per unit	$	0.6950		$	0.5900		$	1.3625		$	1.1550

_____________

(a) Adjusted to include the historical results of the West Coast Logistics Assets. See Notes 1 and 2 for further discussion.

See accompanying notes to condensed combined consolidated financial statements.

Table of Contents

TESORO LOGISTICS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2015			December 31, 2014
	(In millions, except unit amounts)
ASSETS
Current Assets
Cash and cash equivalents (QEPM: $6 and $15, respectively)	$	13		$	19
Receivables, net
Trade	117			122
Affiliate	85			69
Other	—			18
Prepayments and other	11			7
Total Current Assets	226			235
Net Property, Plant and Equipment (QEPM: $459 and $476, respectively)	3,375			3,306
Acquired intangibles, net	959			973
Goodwill	162			164
Investment in Unconsolidated Affiliates	56			57
Other Noncurrent Assets	31			30
Total Assets	$	4,809		$	4,765

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade	$	79		$	126
Affiliate	55			53
Accrued interest and financing costs	30			28
Other current liabilities	66			79
Total Current Liabilities	230			286
Other Noncurrent Liabilities	54			45
Debt, Net of Unamortized Issuance Costs	2,586			2,544
Commitments and Contingencies (Note 7)
Equity
Common unitholders; 80,978,687 units issued and outstanding (80,125,930 in 2014)	1,520			1,474
General partner; 1,631,448 units issued and outstanding (1,631,448 in 2014)	(14		)	(19		)
Noncontrolling interest	433			435
Total Equity	1,939			1,890
Total Liabilities and Equity	$	4,809		$	4,765

See accompanying notes to condensed combined consolidated financial statements.

Table of Contents

TESORO LOGISTICS LP

CONDENSED STATEMENTS OF COMBINED CONSOLIDATED CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2015			2014 (a)
Cash Flows from (used in) Operating Activities:	(In millions)
Net income	$	146		$	73
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization expenses	88			33
Other non-cash operating activities	9			(2		)
Changes in current assets and current liabilities	(27		)	(21		)
Changes in noncurrent assets and liabilities	6			3
Net cash from operating activities	222			86
Cash Flows from (used in) Investing Activities:
Capital expenditures	(160		)	(64		)
Acquisitions	(6		)	—
Proceeds from sale of assets	—			10
Net cash used in investing activities	(166		)	(54		)
Cash Flows from (used in) Financing Activities:
Proceeds from issuance of units, net of issuance costs	45			—
Quarterly distributions to unitholders	(110		)	(63		)
Quarterly distributions to general partner	(30		)	(12		)
Distributions to noncontrolling interest	(18		)	—
Advance distribution in connection with the West Coast Logistics Assets Acquisition	—			(214		)
Borrowings under revolving credit agreement	262			255
Repayments under revolving credit agreement	(223		)	(28		)
Sponsor contribution of equity to the Predecessor	—			4
Other financing activities	12			4
Net cash used in financing activities	(62		)	(54		)
Decrease in Cash and Cash Equivalents	(6		)	(22		)
Cash and Cash Equivalents, Beginning of Period	19			23
Cash and Cash Equivalents, End of Period	$	13		$	1

Supplemental Cash Flow disclosure of non-cash activities:
Interest paid, net of capitalized interest	$	67		$	41
Capital expenditures included in accounts payable at period end	$	42		$	22

_____________

(a) Adjusted to include the historical results of the West Coast Logistics Assets. See Notes 1 and 2 for further discussion.

See accompanying notes to condensed combined consolidated financial statements.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION

Organization

Tesoro Logistics LP (“TLLP” or the “Partnership”) is a fee-based, growth-oriented Delaware limited partnership formed in December 2010 by Tesoro Corporation and its wholly-owned subsidiary, Tesoro Logistics GP, LLC (“TLGP”), our general partner, to own, operate, develop and acquire logistics assets. Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Tesoro Logistics LP, one or more of its consolidated subsidiaries, or all of them taken as a whole. As of June 30, 2015, the words “we,” “us,” “our,” or “ours” generally include our 58% interest in QEP Midstream Partners, LP (“QEPM”) and its subsidiaries as consolidated subsidiaries of TLLP with certain exceptions where there are transactions or obligations between QEPM and TLLP or its other subsidiaries. Unless the context otherwise requires, references in this report to “Tesoro” or our “Sponsor” refer collectively to Tesoro Corporation and any of its subsidiaries, other than TLLP, its subsidiaries and its general partner.

In 2014, we entered into transactions with Tesoro and TLGP, pursuant to which TLLP acquired from Tesoro three truck terminals, ten storage tanks, two rail loading and unloading facilities and a refined products pipeline (the “West Coast Logistics Assets”) effective July 1, 2014 for the terminals, storage tanks and rail facilities and effective September 30, 2014 for the refined products pipeline (collectively referred to as the “West Coast Logistics Assets Acquisition”).

On December 2, 2014, the Partnership acquired all of the limited liability company interests of QEP Field Services, LLC (“QEPFS”) for an aggregate purchase price of approximately $2.5 billion in cash (the “Rockies Natural Gas Business Acquisition”). See Note 2 for additional information regarding the Rockies Natural Gas Business Acquisition.

On April 6, 2015, TLLP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with TLGP, QEPFS, TLLP Merger Sub LLC (“Merger Sub”), QEPM, and QEP Midstream Partners GP, LLC (“QEPM GP”). In July 2015, TLLP and QEPM completed the transaction, in which the Merger Sub merged with and into QEPM, with QEPM surviving the merger as a wholly -owned subsidiary of TLLP (the “Merger”). Following the Merger, QEPM GP remains the general partner of QEPM, and all outstanding common units representing limited partnership interests in QEPM other than QEPM Common Units held by QEPFS (the “QEPM Common Units”) were converted into the right to receive 0.3088 common units representing limited partnership interests in TLLP (the “TLLP Common Units”). The Merger was completed July 22, 2015 and TLLP issued approximately 7.1 million TLLP Common Units to QEPM unitholders. No fractional TLLP Common Units were issued in the Merger, and holders of QEPM Common Units other than QEPFS received cash in lieu of fractional TLLP Common Units.

Principles of Combination and Consolidation and Basis of Presentation

The West Coast Logistics Assets Acquisition was a transfer between entities under common control. As an entity under common control with Tesoro, we record the assets that we acquire from Tesoro on our consolidated balance sheet at Tesoro’s historical basis instead of fair value. Transfers of businesses between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of TLLP have been retrospectively adjusted to include the historical results of the assets acquired in the West Coast Logistics Assets Acquisition for all periods presented. We refer to the historical results of the West Coast Logistics Assets prior to their respective acquisition dates as our “Predecessor.”

The accompanying financial statements and related notes present the results of operations and cash flows of our Predecessor at historical cost. The financial statements of our Predecessor have been prepared from the separate records maintained by Tesoro and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessor had been operated as an unaffiliated entity. Our Predecessor did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment, with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.

The interim combined consolidated financial statements and notes thereto have been prepared by management without audit according to the rules and regulations of the Securities and Exchange Commission (“SEC”) and reflect all adjustments that, in the opinion of management, are necessary for a fair presentation of results for the periods presented. Such adjustments are of a normal recurring nature, unless otherwise disclosed.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Certain information and notes normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) have been condensed or omitted pursuant to the SEC’s rules and regulations. However, management believes that the disclosures presented herein are adequate to present the information fairly. The accompanying interim condensed combined consolidated financial statements and notes should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

Our consolidated financial statements include QEPM, a variable interest entity. As the general partner of QEPM, we have the sole ability to direct the activities of QEPM that most significantly impact its economic performance. We are also considered to be the primary beneficiary for accounting purposes. In the event QEPM incurs a loss, our operating results will reflect QEPM’s loss, net of intercompany eliminations.

We prepare our condensed combined consolidated financial statements in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the amounts of assets and liabilities and revenues and expenses reported as of and during the periods presented. We review our estimates on an ongoing basis using currently available information. Changes in facts and circumstances may result in revised estimates, and actual results could differ from those estimates. The results of operations of the Partnership, or our Predecessor, for any interim period are not necessarily indicative of results for the full year.

We believe the carrying value of our cash and cash equivalents, receivables, accounts payable and certain accrued liabilities approximates fair value. Our fair value assessment incorporates a variety of considerations, including:


•	the short term duration of the instruments (less than 1% of our trade payables and 2% of our trade receivables have been outstanding for greater than 90 days); and


•	the expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The computation of the percentage of the short-term duration of our trade receivables excludes amounts that are greater than 90 days related to XTO Energy Inc.’s (“XTO”) legal dispute with QEPFS. See further discussion regarding the XTO litigation in Note 7.

The fair value of our senior notes is based on prices from recent trade activity and is categorized in level 2 of the fair value hierarchy. The borrowings under our amended revolving credit facility (the “Revolving Credit Facility”), which include a variable interest rate, approximate fair value. The carrying value of our debt was approximately $2.6 billion and the fair value of our debt was approximately $2.7 billion as of June 30, 2015. The carrying value and fair value of our debt were both approximately $2.6 billion as of December 31, 2014. These carrying and fair values of our debt do not include any unamortized issuance costs associated with our total debt.

New Accounting Standards and Disclosures

Revenue Recognition. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 given the FASB’s recent deferral of ASU 2014-09’s effective date. Entities may choose to early adopt ASU 2014-09 as of the original effective date. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the standard to determine the method of adoption and the impact of ASU 2014-09 on our financial statements and related disclosures.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Pushdown Accounting. In November 2014, the SEC released a Staff Accounting Bulletin (“SAB”) overturning portions of the interpretive guidance regarding pushdown accounting. Effective November 18, 2014, the new bulletin aligns the existing guidance to the ASU issued by the FASB in October 2014. Under the new guidance, pushdown accounting can be applied in the separate financial statements of the acquired entity upon completion of the acquisition or in a subsequent period. This impacts the stand-alone financial statements of the subsidiary, but does not alter the existing reporting requirements for the parent company to record the fair value of the acquired assets, liabilities, and non-controlling interests in consolidated financial statements. If pushdown accounting is not applied in the reporting period in which the change-in-control event occurs, an acquired entity will have the option to elect to apply pushdown accounting in a subsequent reporting period. If pushdown accounting is applied, that election is irrevocable. The SEC responded by rescinding its guidance on pushdown accounting, which had required registrants to apply pushdown accounting in certain circumstances. With regard to the Rockies Natural Gas Business Acquisition, we did not elect to apply pushdown accounting to certain acquired entities. Following the Merger, we plan to apply pushdown accounting to all wholly-owned entities acquired as part of the Rockies Natural Gas Business Acquisition.

Consolidation. In February 2015, the FASB issued Accounting Standard Update 2015-02, “Amendments to the Consolidation Analysis” (“ASU 2015-02”). This standard modifies existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015, and requires either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. At this time, we are evaluating the potential impact of this standard on our financial statements, as well as the available transition methods.

Treatment of Predecessor in EPU calculation. In April 2015, the FASB issued Accounting Standard Update 2015-06 (“ASU 2015-06”) which requires a master limited partnership to allocate earnings or losses of transferred net assets for periods prior to asset purchases from an entity under common control entirely to the general partner when calculating earnings per unit (“EPU”). ASU 2015-06 is effective for interim and annual periods beginning after December 15, 2015 and early adoption is permitted. We elected to adopt this guidance beginning in the first quarter of 2015. Adoption of ASU 2015-06 did not impact the disclosed amounts of earnings per unit attributable to limited partners; however, the allocation of earnings presented in our EPU disclosure for the three and six months ended June 30, 2014 has been modified to conform to the requirements of the final standard. There were no asset purchases from Tesoro during the three and six months ended June 30, 2015.

Debt Issuance Costs. In April 2015, the FASB issued Accounting Standard Update 2015-03, “Interest - Imputation of Interest” (“ASU 2015-03”), which will simplify the presentation of debt issuance costs. Under ASU 2015-03, debt issuance costs related to a recognized debt liability will be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability. As a result, our balance sheet will reflect a reclassification of unamortized debt issuance costs from other noncurrent assets to debt. ASU 2015-03 is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We adopted this standard in the first quarter of 2015 and applied the changes retrospectively to prior periods presented. The adoption of this standard resulted in the reclassification of $49 million from other noncurrent assets to debt on the balance sheet at December 31, 2014. Unamortized debt issuance costs of $45 million are recorded as a reduction to debt on the balance sheet at June 30, 2015.

NOTE 2 - ACQUISITIONS

Rockies Natural Gas Business Acquisition

On December 2, 2014, the Partnership closed the acquisition with QEP Resources, Inc. (“QEP Resources”), in which we agreed to purchase all of the limited liability company interests of QEPFS for approximately $2.5 billion in cash. QEPFS is the direct or indirect owner of assets related to, and entities engaged in, natural gas gathering, transportation and processing in or around the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah (collectively, the “Rockies Region”), and the Williston Basin located in North Dakota (the “Bakken Region”). At the acquisition date, QEPFS held an approximate 56% limited partner interest in QEPM and 100% of the limited liability company interests of QEPM GP, which itself held a 2% general partner interest and all of the incentive distribution rights (“IDRs”) in QEPM. Pursuant to the Merger effected on July 22, 2015, we acquired all remaining limited partner interest in QEPM through the issuance of TLLP common units. Refer to Note 1 for further information.

The acquired assets include natural gas and crude oil gathering and transmission pipelines within the Rockies and Bakken Regions, which are reported in our Gathering segment. Additionally, the acquired assets include four natural gas processing complexes and one fractionation facility, the operations of which are reported in our Processing segment.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Finalization of the purchase price allocation is pending and adjustments can be made through the end of our measurement period, which is not to exceed one year from the acquisition date. During the six months ended June 30, 2015, the original purchase price was increased by $6 million for the settlement of acquisition date net working capital with QEP Resources. We recorded $153 million of goodwill in connection with the Rockies Natural Gas Business Acquisition, of which $17 million was included in our Gathering segment, and $136 million was included in our Processing segment. Acquired intangibles other than goodwill are recorded at fair value as of the date acquired, and consist of customer relationships obtained in connection with the Rockies Natural Gas Business Acquisition. We amortize acquired intangibles with finite lives on a straight-line basis over an estimated weighted average useful life of 35 years, and we include the amortization in depreciation and amortization expenses on our condensed statement of combined consolidated operations. The gross carrying value of our intangibles was $976 million and the accumulated amortization was $17 million as of June 30, 2015. During the three and six months ended June 30, 2015, we incurred $7 million and $14 million, respectively, of amortization expense related to these intangibles.

The table below reflects the preliminary acquisition date purchase price allocation as of June 30, 2015 (in millions):



Cash	$	32
Receivables	120
Prepayments and other	8
Property, plant and equipment	1,735
Intangibles	976
Goodwill	153
Investment in unconsolidated affiliates	57
Other noncurrent assets	23
Accounts payable	(72		)
Other current liabilities	(50		)
Other noncurrent liabilities	(34		)
Noncontrolling interest	(432		)
Total purchase price	$	2,516

If the Rockies Natural Gas Business Acquisition had occurred on January 1, 2014, our pro forma revenues would have been $224 million and $449 million for the three and six months ended June 30, 2014, respectively. Our pro forma net income would have been $7 million and $56 million for the three and six months ended June 30, 2014, respectively.

West Coast Logistics Assets Acquisition

On July 1, 2014, we acquired the first portion of the West Coast Logistics Assets and we acquired the second portion of the assets on September 30, 2014, upon receiving the required regulatory approval. The operations of the West Coast Logistics Assets are included in our Terminalling and Transportation segment. These transactions were transfers between entities under common control. See our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the West Coast Logistics Assets Acquisition and the commercial agreements executed in connection with this acquisition.

NOTE 3 - RELATED-PARTY TRANSACTIONS

Affiliate Agreements

The Partnership has various long-term, fee-based commercial agreements with Tesoro under which we provide pipeline transportation, trucking, terminal distribution, storage and petroleum-coke handling services to Tesoro, and Tesoro commits to provide us with minimum monthly throughput volumes of crude oil and refined products.

We entered into the Third Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”) and the Secondment and Logistics Services Agreement (the “Secondment Agreement”) in connection with the West Coast Logistics Assets Acquisition. We also entered into the First Amended and Restated Omnibus Agreement of QEPM (the “QEPM Omnibus Agreement”) and the Keep-Whole Commodity Fee Agreement (the “Keep-Whole Commodity Fee Agreement”) in connection with the Rockies Natural Gas Business Acquisition. See Notes 3 and 11 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of these agreements. On August 3, 2015, subsequent to the Merger, TLLP and QEPM terminated the QEPM Omnibus Agreement.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On February 20, 2015, we entered into an amendment to the Amended Omnibus Agreement. The amendment, effective December 31, 2014, clarifies certain provisions regarding the responsibilities for costs incurred by TLLP in connection with pressure testing conducted on our gathering and transportation system located in the Bakken Region. As a result of the termination of the QEPM Omnibus Agreement discussed above, we further amended the Amended Omnibus Agreement to increase the annual administrative fee payable by the Partnership to Tesoro by $3.6 million. This increase, effective July 1, 2015, accounts for the additional fixed costs and expenses related to the administration of the assets of QEPM and its subsidiaries that was previously payable under the QEPM Omnibus Agreement.

Summary of Affiliate Transactions

A summary of revenue and expense transactions with Tesoro, including expenses directly charged and allocated to our Predecessors, are as follows (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues (a)	$	154	$	117	$	302	$	228
Operating and maintenance expenses	24		20		49		40
Imbalance settlement gains and reimbursements from Tesoro (b)	11		8		19		15
General and administrative expenses	18		10		35		17

____________


(a)	Tesoro accounted for 56% and 88% of our total revenues for the three and six months ended June 30, 2015 and 2014, respectively.

(b)

Includes imbalance settlement gains of $2 million and $3 million for the three months ended June 30, 2015 and 2014, respectively, and $4 million and $5 million for the six months ended June 30, 2015 and 2014, respectively. Also includes reimbursements from Tesoro pursuant to the Amended Omnibus Agreement of $9 million and $5 million for the three months ended June 30, 2015 and 2014, respectively, and $15 million and $10 million for the six months ended June 30, 2015 and 2014, respectively.

Predecessor Transactions. Related-party transactions of our Predecessor were settled through equity. The balance in receivables and accounts payable from affiliated companies represents the amount owed from or to Tesoro related to certain affiliate transactions. Our Predecessor did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment, with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.

Distributions. In accordance with our partnership agreement, the unitholders of our common and general partner interests are entitled to receive quarterly distributions of available cash. In connection with the Rockies Natural Gas Business Acquisition, our general partner has waived its right to $10 million of general partner distributions with respect to IDRs during 2015 (pro rata on a quarterly basis). For the three and six months ended June 30, 2015, our general partner waived $2.5 million and $5 million, respectively, of general partner distributions with respect to IDRs. During the six months ended June 30, 2015, we paid quarterly cash distributions of $68 million to Tesoro and TLGP, including IDRs. On July 23, 2015, we declared a quarterly cash distribution of $0.7225 per unit, which will be paid on August 14, 2015. The distribution will include payments of $38 million to Tesoro and TLGP, including IDRs.

NOTE 4 - NET INCOME PER UNIT

We use the two-class method when calculating the net income per unit applicable to limited partners, because we have more than one participating security. At June 30, 2015, our participating securities consist of common units, general partner units and IDRs. Net income earned by the Partnership is allocated between the limited and general partners in accordance with our partnership agreement. We base our calculation of net income per unit on the weighted average number of common and subordinated limited partner units outstanding during the period.

Diluted net income per unit includes the effects of potentially dilutive units on our common units, which consist of unvested service and performance phantom units. Basic and diluted net income per unit applicable to subordinated limited partners was historically the same, as there were no potentially dilutive subordinated units outstanding. Distributions less than or greater than earnings are allocated in accordance with our partnership agreement.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The calculation of net income per unit is as follows (in millions, except unit and per unit amounts):



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net income	$	72		$	31		$	146		$	73
Net income attributable to noncontrolling interest	(6		)	—			(16		)	—
Net income, excluding noncontrolling interest (a)	66			31			130			73
General partner’s distributions	(2		)	(1		)	(3		)	(2		)
General partner’s IDRs (b)	(15		)	(7		)	(28		)	(13		)
Limited partners’ distributions on common units	(64		)	(29		)	(120		)	(52		)
Limited partners’ distributions on subordinated units (c)	—			(5		)	—			(14		)
Distributions greater than earnings	$	(15	)	$	(11	)	$	(21	)	$	(8	)

General partner’s earnings:
Distributions	$	2		$	1		$	3		$	2
General partner’s IDRs (b)	15			7			28			13
Allocation of distributions greater than earnings (a)	—			(3		)	—			(4		)
Total general partner’s earnings	$	17		$	5		$	31		$	11

Limited partners’ earnings on common units:
Distributions	$	64		$	29		$	120		$	52
Allocation of distributions greater than earnings	(15		)	(7		)	(21		)	(3		)
Total limited partners’ earnings on common units	$	49		$	22		$	99		$	49

Limited partners’ earnings on subordinated units (c):
Distributions	$	—		$	5		$	—		$	14
Allocation of distributions greater than earnings	—			(1		)	—			(1		)
Total limited partners’ earnings on subordinated units	$	—		$	4		$	—		$	13

Weighted average limited partner units outstanding (d):
Common units - basic	80,742,221			46,911,533			80,497,573			43,070,111
Common unit equivalents	68,617			100,891			66,674			99,187
Common units - diluted	80,810,838			47,012,424			80,564,247			43,169,298

Subordinated units - basic and diluted (c)	—			7,543,627			—			11,377,957

Net income per limited partner unit:
Common - basic	$	0.60		$	0.45		$	1.23		$	1.15
Common - diluted	$	0.60		$	0.45		$	1.23		$	1.14
Subordinated - basic and diluted	$	—		$	0.45		$	—		$	1.13

____________

(a)

In April 2015, the FASB issued ASU 2015-06 concerning historical earnings per unit for master limited partnership drop down transactions. We have revised the historical allocation of general partner earnings to include the Predecessor losses TLLP incurred of $3 million and $4 million during the three and six months ended June 30, 2014, respectively. See Note 1 for additional information on the new guidance.

(b)

IDRs entitle the general partner to receive increasing percentages, up to 50%, of quarterly distributions in excess of $0.388125 per unit per quarter. The amount above reflects earnings distributed to our general partner net of $2.5 million and $5 million of IDRs for the three and six months ended June 30, 2015, respectively, waived by TLGP in connection with the Rockies Natural Gas Business Acquisition. See Note 12 of our Annual Report on Form 10-K for the year ended December 31, 2014, for further discussion related to IDRs.


(c)	On May 16, 2014, the subordinated units were converted into common units on a one-for-one basis and thereafter participate on terms equal with all other common units in distributions of available cash. Distributions and the Partnership’s net income were allocated to the subordinated units through May 15, 2014.


(d)	On July 22, 2015, we issued 7.1 million of our common units to QEPM unitholders upon completion of the Merger discussed in Note 1. These units have not been reflected in the weighted average limited partner unit balances.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, at cost, is as follows (in millions):



	June 30, 2015			December 31, 2014
Gathering	$	1,621		$	1,507
Processing	544			539
Terminalling and Transportation	1,510			1,478
Other	19			27
Gross Property, Plant and Equipment	3,694			3,551
Accumulated depreciation	(319		)	(245		)
Net Property, Plant and Equipment	$	3,375		$	3,306

NOTE 6 - DEBT

Our debt balance at June 30, 2015 and December 31, 2014 was as follows (in millions):



	June 30, 2015			December 31, 2014
Total debt	$	2,627		$	2,588
Unamortized issuance costs (a) (b)	(41		)	(44		)
Current maturities	—			—
Debt, net of current maturities and unamortized issuance costs	$	2,586		$	2,544

____________

(a) Includes unamortized premium associated with our 5.875% Senior Notes due 2020 of $4 million and $5 million as of June 30, 2015 and December 31, 2014, respectively.

(b) We adopted ASU 2015-03 in the first quarter of 2015 and applied the changes retrospectively to prior periods presented. The adoption of this standard resulted in the reclassification of $49 million from other noncurrent assets to debt on the balance sheet at December 31, 2014. Unamortized debt issuance costs of $45 million are recorded as a reduction to debt on the balance sheet at June 30, 2015. See Note 1 for further discussion regarding ASU 2015-03.

Revolving Credit Facility

As of June 30, 2015, our Revolving Credit Facility provided for total loan availability of $900 million. We are allowed to request that the loan availability be increased up to an aggregate of $1.5 billion, subject to receiving increased commitments from the lenders. Borrowings are available under the Revolving Credit Facility up to the total loan availability of the facility. Our Revolving Credit Facility is non-recourse to Tesoro, except for TLGP, and is guaranteed by all of our consolidated subsidiaries, with the exception of Rendezvous Gas Services L.L.C., and secured by substantially all of our assets. We had $299 million of borrowings outstanding under the Revolving Credit Facility, resulting in a total unused loan availability of $601 million or 67% of the borrowing capacity as of June 30, 2015. The weighted average interest rate for borrowings under our Revolving Credit Facility was 2.75% at June 30, 2015. The Revolving Credit Facility is scheduled to mature on December 2, 2019.

The Revolving Credit Facility was subject to the following expenses and fees as of June 30, 2015:



Credit Facility	30 day Eurodollar (LIBOR) Rate	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (c)	0.19%	2.50%	3.25%	1.50%	0.50%

____________

(c) We have the option to elect if the borrowings will bear interest at a base rate plus the base rate margin, or a Eurodollar rate, for the applicable period, plus the Eurodollar margin at the time of the borrowing. The applicable margin varies based upon a certain leverage ratio, as defined by the Revolving Credit Facility. We also incur commitment fees for the unused portion of the Revolving Credit Facility at an annual rate. Letters of credit outstanding under the Revolving Credit Facility incur fees at the Eurodollar margin rate.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 7 - COMMITMENTS AND CONTINGENCIES

Tesoro Indemnification

Under the Amended Omnibus Agreement, Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the TLLP initial public offering (“Initial Offering”) and subsequent acquisitions from Tesoro, excluding certain Los Angeles assets acquired from Tesoro in 2013. Under the Carson Assets Indemnity Agreement (the “Carson Assets Indemnity Agreement”), Tesoro retained responsibility for remediation of known environmental liabilities due to the use or operation of certain Los Angeles assets prior to the acquisition dates, and has indemnified the Partnership for any losses incurred by the Partnership arising out of those remediation obligations. See Note 11 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement.

Contingencies

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. The outcome of these matters cannot always be predicted accurately, but TLLP accrues liabilities for these matters if the amount is probable and can be reasonably estimated. Contingencies arising after the closing of the Initial Offering from conditions existing before the Initial Offering, and the subsequent acquisitions from Tesoro that have been identified after the closing of each transaction, will be recorded in accordance with the indemnification terms set forth in the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement. Any contingencies arising from events after the Initial Offering, and the subsequent acquisitions from Tesoro, will be the responsibility of TLLP.

Environmental Liabilities

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. We have accrued liabilities for these expenses and believe these accruals are adequate based on current information and projections that can be reasonably estimated. Our environmental liabilities are estimates using internal and third-party assessments and available information to date. It is possible that these estimates will change as more information becomes available. Our accruals for these environmental expenditures totaled $22 million and $32 million at June 30, 2015 and December 31, 2014, respectively.

Tioga, North Dakota Crude Oil Pipeline Release. In September 2013, the Partnership responded to the release of crude oil in a rural field northeast of Tioga, North Dakota (the “Crude Oil Pipeline Release”). The environmental liabilities related to the Crude Oil Pipeline Release include amounts estimated for remediation activities that will be conducted to restore the site for agricultural use. We spent $10 million during the six months ended June 30, 2015 on remediation related to the Crude Oil Pipeline Release. Our condensed consolidated balance sheet included $15 million and $25 million in accrued environmental liabilities related to the Crude Oil Pipeline Release at June 30, 2015 and December 31, 2014, respectively. This incident was covered by our pollution legal liability insurance policy, subject to a $1 million deductible and a $25 million loss limit. Pursuant to this policy, there were no insurance recovery receivables related to the Crude Oil Pipeline Release at June 30, 2015, and $18 million at December 31, 2014. As of June 30, 2015, the total estimated remediation costs were $42 million, which exceeded our pollution liability legal insurance policy.

Costs to comply with a safety order related to the Crude Oil Pipeline Release issued by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation (“PHMSA”) are not expected to have a material adverse effect on our liquidity, financial position or results of operations.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Chevron Diesel Pipeline Release. On March 18, 2013, Chevron Pipe Line Company and Northwest Terminalling Company (collectively, “Chevron”) detected and responded to the release of diesel fuel (the “Diesel Pipeline Release”) that occurred near Willard, Utah on the northwest products system (the “Northwest Products System”). As a result of this release, a Corrective Action Order (the “CAO”) was issued on March 22, 2013 by PHMSA. The Partnership assumed responsibility for performing additional testing and associated pipeline repairs on the pipeline pursuant to the CAO upon closing the Northwest Products System acquisition. On March 6, 2015, PHMSA issued a closure letter indicating that we have complied with all the terms of the CAO and that no further action is required.

In addition, on April 11, 2013, the Department of Environmental Quality, Division of Water Quality, of the state of Utah issued a notice of violation and compliance order in regard to the Diesel Pipeline Release. In accordance with the sale and purchase agreements related to the Northwest Products System acquisition, as amended, Chevron retained financial and operational responsibility to remediate the site of the Diesel Pipeline Release through June 19, 2015, in addition to paying any monetary fines and penalties assessed by any government authority arising from this incident. Our condensed consolidated balance sheet included $4 million and $6 million in other accrued environmental liabilities at June 30, 2015 and December 31, 2014, respectively related to the assets acquired from Chevron.

Legal

Questar Gas Company v. QEP Field Services Company. QEPFS’ former affiliate, Questar Gas Company (“QGC”) and its affiliate Wexpro, filed a complaint on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the “1993 Agreement”) executed when the parties were affiliates. TLLP has agreed to indemnify QEP Field Services Company (“QEPFSC”) for this claim under the acquisition agreement for QEPFS. Under the 1993 Agreement, certain of QEPFS’ systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service calculation. QGC is disputing the annual calculation of the gathering rate, which has been calculated in the same manner since 1998, without objection by QGC. At the closing of the QEPM initial public offering, the assets and agreement discussed above were assigned to QEPM. QGC amended its complaint to add QEPM as a defendant in the litigation. QEPM was indemnified by the Partnership upon closing of the Rockies Natural Gas Business Acquisition for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the QEPM Omnibus Agreement. QGC has netted $17 million of disputed amounts from its monthly payments of the gathering fees to QEPFS and has continued to net such amounts from its monthly payment to QEPM. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. As a result of the summary judgment, the Partnership assumed a $21 million liability for estimated damages in excess of the amount QGC has netted for disputed amounts. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits. We believe the outcome of this matter will not have a material impact on our liquidity, financial position, or results of operations.

XTO Energy Inc. v. QEP Field Services Company. XTO Energy Inc. (“XTO”) filed a complaint on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the “XTO Agreement”). QEPFS processes XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires QEPFS to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is seeking monetary damages related to QEPFS’ allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. XTO has also withheld payments for amounts unrelated to the allocation of charges they have challenged. While we cannot currently estimate the final amount or timing of the resolution of this matter, we believe the outcome will not have a material impact on our liquidity, financial position, or results of operations.

Other than described above, we did not have any material outstanding lawsuits, administrative proceedings or governmental investigations as of June 30, 2015.

NOTE 8 - EQUITY

We had 52,796,939 common public units outstanding as of June 30, 2015. Additionally, Tesoro owned 28,181,748 of our common units and 1,631,448 of our general partner units (the 2% general partner interest) as of June 30, 2015, which together constitutes a 36% ownership interest in us.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

ATM Program. On June 25, 2014, we filed a prospectus supplement to our shelf registration statement filed with the Securities and Exchange Commission in 2012 (“2012 Shelf”), authorizing the continuous issuance of up to an aggregate of $200 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “ATM Program”). During the three and six months ended June 30, 2015, we issued an aggregate of 373,014 and 819,513 common units, respectively, under our ATM Program, generating net proceeds of approximately $21 million and $45 million, respectively. The net proceeds from sales under the ATM Program will be used for general partnership purposes. The 2012 Shelf expired in June 2015, ending the issuance of units under our ATM Program.

The table below summarizes changes in the number of units outstanding from December 31, 2014 through June 30, 2015 (in units):



	Partnership
	Common (b)	General Partner	Total
Balance at December 31, 2014	80,125,930	1,631,448	81,757,378
Issuance of units under ATM Program	819,513	—	819,513
Unit-based compensation awards (a)	33,244	—	33,244
Balance at June 30, 2015	80,978,687	1,631,448	82,610,135

_____________


(a)	Unit-based compensation awards are presented net of 13,233 units withheld for taxes.


(b)	On July 22, 2015, we issued 7.1 million of our common units to QEPM unitholders upon completion of the Merger discussed in Note 1. These units have not been reflected in the June 30, 2015 common unit balance.

The summarized changes in the carrying amount of our equity are as follows (in millions):



	Partnership
	Common			General Partner			Noncontrolling Interest			Total
Balance at December 31, 2014	$	1,474		$	(19	)	$	435		$	1,890
Equity offering under ATM Program, net of issuance costs	44			1			—			45
Distributions (c)	(110		)	(30		)	(18		)	(158		)
Net income	99			31			16			146
Contributions (d)	11			3			—			14
Other	2			—			—			2
Balance at June 30, 2015	$	1,520		$	(14	)	$	433		$	1,939

_____________

(c) Represents cash distributions declared and paid during the six months ended June 30, 2015 relating to the fourth quarter of 2014 and the first quarter of 2015.


(d)	Includes Tesoro and TLGP contributions to the Partnership primarily related to reimbursements for capital spending pursuant to the Amended Omnibus Agreement.

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Cash Distributions

Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the limited partner unitholders and general partner will receive. In connection with the Rockies Natural Gas Business Acquisition, our general partner has waived its right to $10 million of general partner distributions with respect to IDRs during 2015 (pro rata on a quarterly basis). The table below summarizes the quarterly distributions related to our quarterly financial results:

Quarter Ended

Quarterly Distribution Per Unit

Total Cash Distribution including general partner IDRs (in millions)

Date of Distribution

Unitholders Record Date

December 31, 2014

0.6675

February 13, 2015

February 2, 2015

March 31, 2015

0.6950

May 15, 2015

May 4, 2015

June 30, 2015 (e)

0.7225

August 14, 2015

August 3, 2015

_____________

(e) This distribution was declared on July 23, 2015 and will be paid on the date of distribution.

NOTE 9 - SEGMENT DISCLOSURES

Our revenues are derived from three operating segments: Gathering, Processing, Terminalling and Transportation. Our Gathering segment consists of crude oil and natural gas gathering systems in the Bakken and Rockies Regions, including our affiliate QEPM. Our Processing segment consists of four gas processing complexes, including Green River Processing, LLC, which owns one fractionation facility and two gas processing complexes. Our Terminalling and Transportation segment consists of:


•	24 crude oil and refined products terminals and storage facilities in the western and midwestern U.S.;


•	four marine terminals in California;


•	130 miles of pipelines which transport products and crude oil from Tesoro’s refineries to nearby facilities in Salt Lake City and Los Angeles;


•	the Northwest Products Pipeline, which includes a regulated common carrier products pipeline running from Salt Lake City, Utah to Spokane, Washington and a jet fuel pipeline to the Salt Lake City International Airport;


•	a rail-car unloading facility in Washington;


•	a petroleum coke handling and storage facility in Los Angeles; and


•	a regulated common carrier refined products pipeline system connecting Tesoro’s Kenai refinery to terminals in Anchorage, Alaska.

Our revenues are generated from third-party contracts and from commercial agreements we have entered into with Tesoro under which Tesoro pays us fees for gathering crude oil and natural gas, processing natural gas and distributing, transporting and storing crude oil, refined products, natural gas and natural gas liquids. The commercial agreements with Tesoro are described in greater detail in Note 3 to our Annual Report on Form 10-K for the year ended December 31, 2014. We do not have any foreign operations.

Our operating segments are strategic business units that offer different services in various geographical locations. We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses, interest and financing costs and equity in earnings of unconsolidated affiliates are excluded from segment operating income as they are not directly attributable to a specific operating segment. Identifiable assets are those used by the segment, whereas other assets are principally cash and other assets that are not associated with a specific operating segment.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Segment information is as follows (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues
Gathering:
Affiliate	$	27		$	25		$	53		$	48
Third-party	62			2			113			4
Total Gathering	89			27			166			52
Processing
Affiliate	25			—			45			—
Third-party	42			—			89			—
Total Processing	67			—			134			—
Terminalling and Transportation:
Affiliate	102			92			204			180
Third-party	17			14			34			28
Total Terminalling and Transportation	119			106			238			208
Total Segment Revenues	$	275		$	133		$	538		$	260
Segment Operating Income
Gathering	$	45		$	12		$	79		$	23
Processing	24			—			48			—
Terminalling and Transportation	55			40			117			93
Total Segment Operating Income	124			52			244			116
Unallocated general and administrative expenses	(15		)	(4		)	(27		)	(8		)
Interest and financing costs, net	(38		)	(17		)	(75		)	(35		)
Equity in earnings of unconsolidated affiliates	1			—			4			—
Net Income	$	72		$	31		$	146		$	73

Capital Expenditures
Gathering	$	54		$	33		$	105		$	51
Processing	4			—			5			—
Terminalling and Transportation	19			15			33			23
Total Capital Expenditures	$	77		$	48		$	143		$	74

NOTE 10 - CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Separate condensed consolidating financial information of Tesoro Logistics LP (the “Parent”), subsidiary guarantors and non-guarantors are presented below. QEPFS, our wholly-owned subsidiary acquired on December 2, 2014, and certain of its subsidiaries were elected guarantors of these obligations in January 2015. As of June 30, 2015, TLLP and certain subsidiary guarantors have fully and unconditionally guaranteed our registered 2020 Senior Notes and 2021 Senior Notes. As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information, which should be read in conjunction with the accompanying condensed consolidated financial statements and notes thereto. The December 31, 2014 balance sheet has been adjusted to conform to the guarantor structure as of June 30, 2015. This information is provided as an alternative to providing separate financial statements for guarantor subsidiaries. Separate financial statements of the Partnership’s subsidiary guarantors are not included because the guarantees are full and unconditional and these subsidiary guarantors are 100% owned and are jointly and severally liable for TLLP’s outstanding senior notes, except for QEPM and Green River Processing, LLC (“Green River Processing”). See page F-1 for the separate financial statements of QEPM and Green River Processing. The separate condensed consolidating financial information is presented using the equity method of accounting for investments in subsidiaries. Intercompany transactions between subsidiaries are presented gross and eliminated in the eliminations column.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The parent company of the Partnership has no independent assets or operations and, prior to the Rockies Natural Gas Business Acquisition, the Partnership’s operations were only conducted by wholly-owned guarantor subsidiaries, other than Tesoro Logistics Finance Corp., an indirect wholly-owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture. There were no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or its guarantors represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act. As a result, we have not provided condensed consolidating financial information for the three and six months ended June 30, 2014.

Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries			Non Wholly-owned Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
Affiliate	$	—		$	142		$	14		$	7		$	(9	)	$	154
Third-party	—			71			49			2			(1		)	121
Total Revenues	—			213			63			9			(10		)	275
Costs and Expenses
Operating and maintenance expenses	—			86			27			1			(9		)	105
Imbalance settlement gains and reimbursements from Tesoro	—			(11		)	—			—			—			(11		)
General and administrative expenses	6			14			8			—			—			28
Depreciation and amortization expenses	—			29			6			3			6			44
Loss on asset disposals and impairments	—			—			5			—			(5		)	—
Total Costs and Expenses	6			118			46			4			(8		)	166
Operating Income (Loss)	(6		)	95			17			5			(2		)	109
Interest and financing costs, net	(40		)	1			(1		)	—			2			(38		)
Equity in earnings of unconsolidated affiliates	—			—			1			—			—			1
Equity in earnings of subsidiaries	112			16			4			—			(132		)	—
Interest income	—			2			—			—			(2		)	—
Net Income	$	66		$	114		$	21		$	5		$	(134	)	$	72

Net income attributable to noncontrolling interest	—			—			(5		)	(1		)	—			(6		)
Net income attributable to partners	$	66		$	114		$	16		$	4		$	(134	)	$	66

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NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries			Non Wholly-owned Guarantors			Non-Guarantors			Eliminations			Consolidated
Revenues
Affiliate	$	—		$	279		$	27		$	13		$	(17	)	$	302
Third-party	—			140			96			3			(3		)	236
Total Revenues	—			419			123			16			(20		)	538
Costs and Expenses
Operating and maintenance expenses	—			164			51			1			(17		)	199
Imbalance settlement gains and reimbursements from Tesoro	—			(19		)	—			—			—			(19		)
General and administrative expenses	12			27			14			—			—			53
Depreciation and amortization expenses	—			58			13			6			11			88
Loss on asset disposals and impairments	—			—			5			—			(5		)	—
Total Costs and Expenses	12			230			83			7			(11		)	321
Operating Income (Loss)	(12		)	189			40			9			(9		)	217
Interest and financing costs, net	(79		)	4			(2		)	—			2			(75		)
Equity in earnings of unconsolidated affiliates	—			1			3			—			—			4
Equity in earnings of subsidiaries	221			34			7			—			(262		)	—
Interest income	—			2			—			—			(2		)	—
Net Income	$	130		$	230		$	48		$	9		$	(271	)	$	146

Net income attributable to noncontrolling interest	—			—			(14		)	(2		)	—			(16		)
Net income attributable to partners	$	130		$	230		$	34		$	7		$	(271	)	$	130

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet as of June 30, 2015

(In millions)



	Parent		Guarantor Subsidiaries		Non Wholly-owned Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	2	$	8	$	3	$	—		$	13
Receivables, net
Trade	—		87		29		1		—			117
Affiliate	3		77		18		2		(15		)	85
Prepayments and other	8		4		1		—		(2		)	11
Total Current Assets	11		170		56		6		(17		)	226
Net property, plant and equipment	—		2,161		554		183		477			3,375
Acquired intangibles, net	—		581		—		—		378			959
Goodwill	—		68		—		—		94			162
Investment in unconsolidated affiliates	—		18		24		—		14			56
Investments in subsidiaries	4,574		1,330		145		—		(6,049		)	—
Long-term intercompany receivable	—		627		1		—		(628		)	—
Other noncurrent assets	1		30		—		—		—			31
Total Assets	$	4,586	$	4,985	$	780	$	189	$	(5,731	)	$	4,809

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade	$	3	$	68	$	8	$	—	$	—		$	79
Affiliate	1		62		7		—		(15		)	55
Accrued interest and financing costs	30		—		—		—		—			30
Other current liabilities	22		40		6		—		(2		)	66
Total Current Liabilities	56		170		21		—		(17		)	230
Long-term intercompany payable	446		—		203		2		(651		)	—
Other noncurrent liabilities	—		35		27		1		(9		)	54
Debt, net of unamortized issuance costs	2,578		8		—		—		—			2,586
Equity - TLLP	1,506		4,772		500		145		(5,417		)	1,506
Equity - Noncontrolling interest	—		—		29		41		363			433
Total Liabilities and Equity	$	4,586	$	4,985	$	780	$	189	$	(5,731	)	$	4,809

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2014 (a)

(In millions)



	Parent		Guarantor Subsidiaries			Non Wholly-owned Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	—	$	(2	)	$	19	$	2	$	—		$	19
Receivables, net
Trade	—		93			28		1		—			122
Affiliate	3		59			7		—		—			69
Other	—		18			—		—		—			18
Prepayments and other	3		4			—		—		—			7
Total Current Assets	6		172			54		3		—			235
Net property, plant and equipment	1		2,073			566		188		478			3,306
Acquired intangibles, net	—		590			—		—		383			973
Goodwill	—		48			—		—		116			164
Investment in unconsolidated affiliates	—		18			25		—		14			57
Investments in subsidiaries	4,348		1,325			152		—		(5,825		)	—
Long-term intercompany receivable	—		516			—		5		(521		)	—
Other noncurrent assets	—		30			—		—		—			30
Total Assets	$	4,355	$	4,772		$	797	$	196	$	(5,355	)	$	4,765

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade	$	6	$	102		$	18	$	—	$	—		$	126
Affiliate	2		45			6		—		—			53
Accrued interest and financing costs	28		—			—		—		—			28
Other current liabilities	21		56			4		—		(2		)	79
Total Current Liabilities	57		203			28		—		(2		)	286
Long-term intercompany payable	307		—			214		—		(521		)	—
Other noncurrent liabilities	—		25			29		1		(10		)	45
Debt, net of unamortized issuance costs	2,536		8			—		—		—			2,544
Equity - TLLP	1,455		4,536			497		152		(5,185		)	1,455
Equity - Noncontrolling interest	—		—			29		43		363			435
Total Liabilities and Equity	$	4,355	$	4,772		$	797	$	196	$	(5,355	)	$	4,765

_____________

(a) Presentation of the condensed consolidating balance sheet as of December 31, 2014 has been adjusted to conform to the current period presentation.

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TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries			Non Wholly-owned Guarantors			Non-Guarantors			Eliminations			Consolidated
Cash Flows from (used in) Operating Activities:
Net cash from (used in) operating activities	$	(93	)	$	297		$	54		$	13		$	(49	)	$	222
Cash Flows from (used in) Investing Activities:
Capital expenditures	—			(152		)	(8		)	—			—			(160		)
Acquisitions	—			(6		)	—			—			—			(6		)
Investments in subsidiaries	(6		)	(5		)	—			—			11			—
Net cash used in investing activities	(6		)	(163		)	(8		)	—			11			(166		)
Cash Flows from (used in) Financing Activities:
Proceeds from issuance of common units, net of issuance costs	45			—			—			—			—			45
Quarterly distributions to unitholders	(110		)	—			(19		)	—			19			(110		)
Quarterly distributions to general partner	(30		)	—			(1		)	(14		)	15			(30		)
Distributions to noncontrolling interest	—			—			(14		)	(4		)	—			(18		)
Distributions to subsidiaries	—			—			(15		)	—			15			—
Borrowings under revolving credit agreement	262			(29		)	29			—			—			262
Repayments under revolving credit agreement	(223		)	36			(36		)	—			—			(223		)
Contributions	—			6			5			—			(11		)	—
Intercompany borrowings (payments)	143			(143		)	(6		)	6			—			—
Capital contributions by affiliate	12			—			—			—			—			12
Net cash from (used in) financing activities	99			(130		)	(57		)	(12		)	38			(62		)
Increase (Decrease) in Cash and Cash Equivalents	—			4			(11		)	1			—			(6		)
Cash and Cash Equivalents, Beginning of Period	—			(2		)	19			2			—			19
Cash and Cash Equivalents, End of Period	$	—		$	2		$	8		$	3		$	—		$	13

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

Unless the context otherwise requires, references in this report to “Tesoro Logistics LP,” “TLLP,” “the Partnership,” “we,” “us” or “our” refer to Tesoro Logistics LP, one or more of its consolidated subsidiaries or all of them taken as a whole. The words “we,” “us,” “our,” or “ours” generally include our interest in QEP Midstream Partners, LP (“QEPM”), and its subsidiaries as consolidated subsidiaries of TLLP with certain exceptions where there are transactions or obligations between QEPM and TLLP or its other subsidiaries. Unless the context otherwise requires, references in this report to “Tesoro” or our “Sponsor” refer collectively to Tesoro Corporation and any of its subsidiaries, other than Tesoro Logistics LP, its subsidiaries and its general partner.

In 2014, as part of our strategy to make capital investments to expand our existing asset base, we entered into transactions with Tesoro and Tesoro Logistics GP, LLC (“TLGP”), our general partner, pursuant to which TLLP acquired from Tesoro three truck terminals, ten storage tanks, two rail loading and unloading facilities and a refined products pipeline (the “West Coast Logistics Assets”) effective July 1, 2014 for the terminals, storage tanks and rail facilities and effective September 30, 2014 for the refined products pipeline (collectively referred to as the “West Coast Logistics Assets Acquisition”). In connection with the West Coast Logistics Assets Acquisition we entered into the Third Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”). See Notes 3 and 11 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of this agreement.

The West Coast Logistics Assets Acquisition was a transfer between entities under common control. Accordingly, the financial information of TLLP contained herein has been retrospectively adjusted to include the historical results of the assets acquired in the West Coast Logistics Assets Acquisition. We refer to the historical results of the West Coast Logistics Assets prior to the respective acquisition dates, as our “Predecessor.” Our financial results may not be comparable as our Predecessor recorded revenues, general and administrative expenses and financed operations differently than the Partnership. See “Factors Affecting the Comparability of Our Financial Results” in our Annual Report on Form 10-K for the year ended December 31, 2014.

On December 2, 2014, we acquired QEP Field Services, LLC (“QEPFS”), which as of June 30, 2015 includes a 55.7% limited partner interest in QEP Midstream Partners, LP (“QEPM”) and 100% of the limited liability company interests of QEPM’s general partner, QEP Midstream Partners GP, LLC (“QEPM GP”), which itself holds a 2% general partner interest and 100% of the incentive distribution rights (“IDRs”) in QEPM from QEP Resources, Inc. (“QEP Resources”) (collectively the “Rockies Natural Gas Business Acquisition”). Pursuant to the Merger effected on July 22, 2015, we acquired all remaining limited partner interest in QEPM through the issuance of TLLP common units. Refer to Note 1 for further information.

Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Important Information Regarding Forward-Looking Statements” on page 39 for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

This section should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.

BUSINESS STRATEGY AND OVERVIEW

We are a leading full-service logistics company operating primarily in the western and mid-continent regions of the United States. We own and operate over 3,500 miles of crude oil, refined products and natural gas pipelines and 28 crude oil and refined products truck and marine terminals and have over 9 million barrels of storage capacity. In addition, we own and operate four natural gas processing complexes and one fractionation facility. Our assets are categorized into a Gathering segment, a Processing segment and a Terminalling and Transportation segment. For both the three and six months ended June 30, 2015, approximately 56% of our total revenues were derived from Tesoro under various long-term, fee-based commercial agreements many of which include minimum volume commitments.

Our financial information includes the historical results of our Predecessor and the results of TLLP for the three and six months ended June 30, 2014. The financial statements of our Predecessor have been prepared from the separate records maintained by Tesoro and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessor had been operated as an unaffiliated entity. Most notably, this applies to the revenue associated with the terms of the commercial agreements as our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment, with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.

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We generate revenues by charging fees for gathering crude oil and natural gas, for terminalling, transporting and storing crude oil and refined products and for processing natural gas. We are generally not exposed to commodity price risk with respect to any of the crude oil, natural gas, natural gas liquids (“NGLs”) or refined products that we handle, with the exception of a nominal amount of condensate. For the NGLs that we handle under keep-whole agreements, the Partnership has a fee-based processing agreement with Tesoro which minimizes the impact of commodity price movement during the annual period subsequent to renegotiation of terms and pricing each year. We do not engage in the trading of crude oil, natural gas, NGLs or refined products; therefore, we have minimal direct exposure to risks associated with commodity price fluctuations. However, through their effects on our customers’ operations, these risks indirectly influence our activities and results of operations over the long term.

Rockies Natural Gas Business Acquisition. As a part of our strategy to focus on stable fee-based business, optimize existing assets, and grow through strategic acquisitions, we acquired QEPFS on December 2, 2014 for an aggregate purchase price of approximately $2.5 billion. The purchase price also includes post-closing adjustments for net working capital. QEPFS either directly or indirectly owns assets related to, and entities engaged in, natural gas gathering, transportation and processing in or around the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah (collectively, the “Rockies Region”), and the Williston Basin located in North Dakota (the “Bakken Region”).

The assets acquired in the Rockies Natural Gas Business Acquisition include over 2,000 miles of natural gas and crude oil gathering and transmission pipelines, with natural gas throughput capacity of 2.9 billion cubic feet per day and crude oil throughput capacity of over 54,000 barrels per day (“bpd”). Additionally, the acquired assets include four natural gas processing complexes with total capacity of 1.5 billion cubic feet per day and one fractionation facility with 15,000 bpd of throughput capacity (“Rockies Natural Gas Assets”). The natural gas and crude oil gathering operations are included in our Gathering segment, and the natural gas processing operations are included in the Processing segment.

On April 6, 2015, TLLP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with TLGP, QEPFS, TLLP Merger Sub LLC (“Merger Sub”), QEPM, and QEP Midstream Partners GP, LLC (“QEPM GP”). In July 2015, TLLP and QEPM completed the transaction, in which the Merger Sub merged with and into QEPM, with QEPM surviving the merger as a wholly- owned subsidiary of TLLP (the “Merger”). Following the Merger, QEPM GP remains the general partner of QEPM, and all outstanding common units representing limited partnership interests in QEPM other than QEPM Common Units held by QEPFS (the “QEPM Common Units”) were converted into the right to receive 0.3088 common units representing limited partnership interests in TLLP (the “TLLP Common Units”). The Merger was completed July 22, 2015 and TLLP issued approximately 7.1 million TLLP Common Units to QEPM unitholders. No fractional TLLP Common Units were issued in the Merger, and holders of QEPM Common Units other than QEPFS received cash in lieu of fractional TLLP Common Units.

Open Season. In December 2014, we launched an additional binding open season, to assess shipper interest in firm priority capacity on the High Plains Pipeline. While we did not receive interest at that time to move forward with the full open season project, based on shipper interest, as well as current strong demand for pipeline take-away capacity in the McKenzie County area of North Dakota, we intend to proceed with a portion of the expansion projects in the core Bakken production areas. The projects are expected to provide incremental capacity to move crude oil from the core production areas to our existing interconnections with rail facilities and regional pipelines. The projects will require estimated capital expenditures of approximately $50 million and are expected to be completed in 2016.

Strategy and Goals

Our primary business objectives are to maintain stable cash flows and to increase our quarterly cash distribution per unit over time. We intend to accomplish these objectives by executing the following strategies:


•	focus on opportunities to provide committed fee-based logistics services to Tesoro and third parties;


•	evaluate investment opportunities that may arise from the growth of Tesoro’s refining and marketing business or from increased third-party activity to make capital investments to expand our existing asset base;


•	pursue accretive acquisitions of complementary assets from Tesoro as well as third parties; and


•	seek to enhance the profitability of our existing assets by pursuing opportunities to add Tesoro and third-party volumes, improve operating efficiencies and increase utilization.

We have been implementing our strategy and goals discussed above, allowing us to steadily increase our cash flow available to be distributed to unitholders (“Distributable Cash Flow”) and to increase our distributions by 17% over the last year.

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Relative to these goals, in 2015, we intend to continue to implement this strategy and have completed or announced plans to:


•	expand our assets on our gathering and transportation system, located in the Bakken Region (the “High Plains System”) in support of growing third-party demand for transportation services and Tesoro’s increased demand for Bakken crude oil in the mid-continent and west coast refining systems, including:


◦	further expanding capacity and capabilities of our common carrier pipeline in North Dakota and Montana (the “High Plains Pipeline”);


◦	expanding our gathering footprint in the Bakken Region, including crude oil, natural gas and water, to enhance and improve overall basin logistics efficiencies;


◦	adding other origin and destination points on the High Plains System to increase volumes; and


◦	expanding utilization of our proprietary truck fleet, which should generate cost and operating efficiencies.


•	increase our terminalling volumes by expanding capacity and growing our third-party services at certain of our terminals;


•	optimize Tesoro volumes and grow third-party volumes at our West Coast Logistics Assets; and


•	expand and optimize our assets acquired in the Rockies Natural Gas Business Acquisition.

Current Market Conditions

Over the past twelve months, the spot price of the commodities that we handle, including crude oil, natural gas, natural gas liquids and refined products, has declined significantly. This decline is due in part to rapid growth of domestic supplies of these commodities. A weakened and volatile commodity environment has created challenges for our crude oil and natural gas producer customers as they assess their future drilling and production plans. For our downstream refining and marketing customers, this has led, in part, to an increased demand for refined products. We continue to monitor the impact of these changes in market prices on our business, including values recognized in connection with the recently acquired Rockies Natural Gas Business. We believe our diversified portfolio of business is sufficient to continue to meet our goals and objectives outlined above.

RESULTS OF OPERATIONS

A discussion and analysis of the factors contributing to our results of operations presented below includes the combined financial results of our Predecessors and the consolidated financial results of TLLP. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.

Non-GAAP Measures

Our management uses a variety of financial and operating measures to analyze operating segment performance. Our management also uses additional measures that are known as “non-GAAP” financial measures in its evaluation of past performance and prospects for the future to supplement our financial information presented in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). These measures are significant factors in assessing our operating results and profitability and include earnings before interest, income taxes, loss attributable to Predecessors and depreciation and amortization expense (“EBITDA”), Adjusted EBITDA and Distributable Cash Flow. In 2015, we updated our presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to include noncontrolling interest in these calculations. Management uses EBITDA and Adjusted EBITDA to manage our operations and business as a whole without regard to amounts attributable to noncontrolling interests. As a result of the change in EBITDA and Adjusted EBITDA, our definition of Distributable Cash Flow was revised to adjust for noncontrolling interest amounts since they continue to impact cash available for distribution to our unitholders.

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We define adjusted EBITDA as EBITDA plus or minus amounts determined to be “special items” by our management based on their unusual nature and relative significance to earnings in a certain period. We define Distributable Cash Flow as adjusted EBITDA plus or minus amounts determined to be “special items” by our management based on their relative significance to cash flow in a certain period. We define Pro Forma Distributable Cash Flow as Distributable Cash Flow plus or minus adjustments for the acquisition of noncontrolling interest in connection with the Merger. We provide complete reconciliation and discussion of items identified as special items with our presentation of adjusted EBITDA and Distributable Cash Flow. Prior periods have been adjusted to conform to current presentation. EBITDA, adjusted EBITDA, Distributable Cash Flow and Pro Forma Distributable Cash Flow are not measures prescribed by U.S. GAAP but are supplemental financial measures that are used by management and may be used by external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess:


•	our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;


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


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


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

The U.S. GAAP measures most directly comparable to EBITDA and adjusted EBITDA are net income and net cash from operating activities. EBITDA and adjusted EBITDA should not be considered as an alternative to U.S. GAAP net income or net cash from operating activities. EBITDA and adjusted EBITDA have important limitations as analytical tools, because they exclude some, but not all, items that affect net income and net cash from operating activities. We have updated our Distributable Cash Flow to adjust for the impact of our noncontrolling interest acquired in the Rockies Natural Gas Business. The U.S. GAAP measure most directly comparable to Distributable Cash Flow and Pro Forma Distributable Cash Flow is net income.

These non-GAAP financial measures should not be considered in isolation or as a substitute for analysis of our results as reported under U.S. GAAP. Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, because they may be defined differently by other companies in our industry, thereby diminishing their utility.

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Summary

The following table and discussion is a summary of our results of operations for the three and six months ended June 30, 2015 and 2014, including a reconciliation of EBITDA and adjusted EBITDA to net income and net cash from operating activities and Distributable Cash Flow to net income (in millions, except unit and per unit amounts). Our financial results may not be comparable as our Predecessor recorded revenues and general and administrative expenses, and financed operations differently than the Partnership. See “Factors Affecting the Comparability of Our Financial Results” in our Annual Report on Form 10-K for the year ended December 31, 2014.



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014 (a)			2015			2014 (a)
Revenues
Gathering	$	89		$	27		$	166		$	52
Processing	67			—			134			—
Terminalling and Transportation (b)	119			106			238			208
Total Revenues	275			133			538			260
Costs and Expenses
Operating and maintenance expenses (c)	94			55			180			100
General and administrative expenses	28			13			53			23
Depreciation and amortization expenses	44			17			88			33
Net gain on asset disposals and impairments	—			—			—			(4		)
Total Costs and Expenses	166			85			321			152
Operating Income	109			48			217			108
Interest and financing costs, net	(38		)	(17		)	(75		)	(35		)
Equity in earnings of unconsolidated affiliates	1			—			4			—
Net Income	$	72		$	31		$	146		$	73

Loss attributable to Predecessors	—			3			—			4
Net income attributable to noncontrolling interest	(6		)	—			(16		)	—
Net Income attributable to Partners	66			34			130			77
General partner’s interest in net income, including incentive distribution rights	(17		)	(8		)	(31		)	(15		)
Limited partners’ interest in net income	$	49		$	26		$	99		$	62

Net income per limited partner unit:
Common - basic	$	0.60		$	0.45		$	1.23		$	1.15
Common - diluted	$	0.60		$	0.45		$	1.23		$	1.14
Subordinated - basic and diluted	$	—		$	0.45		$	—		$	1.13

Weighted average limited partner units outstanding:
Common units - basic	80,742,221			46,911,533			80,497,573			43,070,111
Common units - diluted	80,810,838			47,012,424			80,564,247			43,169,298
Subordinated units - basic and diluted	—			7,543,627			—			11,377,957

EBITDA (d)	$	154		$	67		$	309		$	144
Adjusted EBITDA (d)	$	155		$	70		$	323		$	145
Distributable Cash Flow (d)	$	89		$	51		$	202		$	117

See pages 28 and 29 for footnotes to this table.

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	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014 (a)			2015			2014 (a)
Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net Income:
Net income	$	72		$	31		$	146		$	73
Loss attributable to Predecessors	—			3			—			4
Depreciation and amortization expenses, net of Predecessor expense	44			16			88			32
Interest and financing costs, net of capitalized interest	38			17			75			35
EBITDA (d)	$	154		$	67		$	309		$	144
Net gain on asset disposals and impairments	—			—			—			(4		)
Acquisition costs included in general and administrative expenses	1			—			1			—
Billing of deficiency payments (e)	—			—			13			—
Inspection and maintenance capital expenses associated with the Northwest Products System	—			3			—			5
Adjusted EBITDA (d)	$	155		$	70		$	323		$	145
Interest and financing costs, net	(38		)	(17		)	(75		)	(35		)
Maintenance capital expenditures (f)	(15		)	(5		)	(24		)	(7		)
Other adjustments for noncontrolling interest (g)	(12		)	—			(20		)	—
Net income attributable to noncontrolling interest	(6		)	—			(16		)	—
Change in deferred revenue	(1		)	1			4			1
Amortization of debt issuance costs	2			1			4			2
Reimbursement for maintenance capital expenditures (f)	2			1			3			1
Unit-based compensation expense	2			—			3			—
Proceeds from sale of assets	—			—			—			10
Distributable Cash Flow (d)	$	89		$	51		$	202		$	117
Pro forma adjustment for acquisition of noncontrolling interest (h)	19			—			36			—
Pro Forma Distributable Cash Flow (d)	$	108		$	51		$	238		$	117

Reconciliation of EBITDA to Net Cash from Operating Activities:
Net cash from operating activities	$	70		$	17		$	222		$	86
Interest and financing costs, net	38			17			75			35
Changes in assets and liabilities	53			32			21			18
Amortization of debt issuance costs	(2		)	(1		)	(4		)	(2		)
Unit-based compensation expense	(2		)	—			(3		)	—
Earnings from unconsolidated affiliates, net of distributions	(3		)	—			(2		)	—
Predecessor impact	—			2			—			3
Net gain on asset disposals and impairments	—			—			—			4
EBITDA (d)	$	154		$	67		$	309		$	144

____________


(a)	Includes the historical results related to the Partnership and Predecessor for the three and six months ended June 30, 2014.


(b)	Our Predecessor did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment for assets acquired in the acquisitions from Tesoro prior to the effective date of each acquisition with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.

(c)

Operating and maintenance expenses includes imbalance settlement gains of $2 million and $3 million for the three months ended June 30, 2015 and 2014, respectively, and $4 million and $5 million for the six months ended June 30, 2015 and 2014, respectively. Also includes reimbursements from Tesoro pursuant to the Amended Omnibus Agreement of $9 million and $5 million for the three months ended June 30, 2015 and 2014, respectively, and $15 million and $10 million for the six months ended June 30, 2015 and 2014, respectively.

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(d)	For a definition of EBITDA, Adjusted EBITDA, Distributable Cash Flow and Pro Forma Distributable Cash Flow, see “Non-GAAP Financial Measures.”

(e)

Several of our contracts contain minimum volume commitments that allow us to charge the customer a deficiency payment if the customer’s actual throughput volumes are less than its minimum volume commitments for the applicable period. In certain contracts, if a customer makes a deficiency payment, that customer may be entitled to offset gathering fees or processing fees in one or more subsequent periods to the extent that such customer’s throughput volumes in those periods exceed its minimum volume commitment. Depending on the specific terms of the contract, revenue under these agreements may be classified as deferred revenue and recognized once all contingencies or potential performance obligations associated with these related volumes have either been satisfied through the gathering or processing of future excess volumes of natural gas, or are expected to expire or lapse through the passage of time pursuant to terms of the applicable agreement. During the six months ended June 30, 2015, we invoiced customers for deficiency payments. We did not recognize $13 million of revenue related to the billing period as it represented an opening balance sheet asset for the Rockies Natural Gas Business Acquisition; however, TLLP is entitled to the cash receipt from such billings. The timing and amount of deficiency billings vary based on actual shortfall and terms under the applicable agreements.


(f)	Maintenance capital expenditures include expenditures required to ensure the safety, reliability, integrity and regulatory compliance of our assets. Maintenance capital expenditures included in the Distributable Cash Flow calculation are presented net of Predecessor amounts.


(g)	Adjustments represent cash distributions in excess of (or less than) our controlling interest in income and depreciation as well as other adjustments for depreciation and maintenance capital expenditures applicable to the noncontrolling interest obtained in the Rockies Natural Gas Business Acquisition.


(h)	Reflects the adjustment to include the noncontrolling interest in QEPM as controlling interest based on the pro forma assumption that the Merger occurred on January 1, 2015.

Consolidated Results

Our net income for the three months ended June 30, 2015 (“2015 Quarter”) increased $41 million to $72 million from $31 million for the three months ended June 30, 2014 (“2014 Quarter”). The increase in net income was due to an increase in revenue of $142 million, or 107%, to $275 million driven primarily by the Rockies Natural Gas Business Acquisition and the West Coast Logistics Assets Acquisition. The increase in revenue was partially offset by:


•	an increase in operating and maintenance expenses of $39 million, or 71%, primarily related to the operations of the Rockies Natural Gas Assets and the West Coast Logistics Assets;


•	an increase in depreciation and amortization expenses of $27 million, primarily as a result of depreciation on the assets and intangibles acquired in the Rockies Natural Gas Business Acquisition;


•	an increase in net interest and financing costs of $21 million, primarily related to the issuance of senior notes used to fund the Rockies Natural Gas Business Acquisition; and


•	an increase in general and administrative expenses of $15 million, or 115%, primarily related to higher allocated overhead to support the Partnership’s growing business as well as $3 million related to acquisition and integration expenses for the Rockies Natural Gas Business Acquisition and the Merger.

Our net income for the six months ended June 30, 2015 (“2015 Period”) increased $73 million to $146 million from $73 million for the six months ended June 30, 2014 (“2014 Period”). The increase in net income was due to an increase in revenue of $278 million, or 107%, to $538 million driven primarily by the Rockies Natural Gas Business Acquisition and the West Coast Logistics Assets Acquisition. The increase in revenue was partially offset by:


•	an increase in operating and maintenance expenses of $80 million, or 80%, primarily related to the operations of the Rockies Natural Gas Assets and the West Coast Logistics Assets;


•	an increase in depreciation and amortization expenses of $55 million, primarily as a result of depreciation on the assets and intangibles acquired in the Rockies Natural Gas Business Acquisition;


•	an increase in net interest and financing costs of $40 million, related to the issuance of senior notes used to fund the Rockies Natural Gas Business Acquisition; and


•	an increase in general and administrative expenses of $30 million, or 130%, primarily related to higher allocated overhead to support the Partnership’s growing business as well as $6 million related to acquisition and integration expenses for the Rockies Natural Gas Business Acquisition and the Merger.

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Gathering Segment

The following table and discussion is an explanation of our results of operations of the Gathering segment for the three and six months ended June 30, 2015 and 2014 (in millions, except volumes, revenue per barrel and revenue per million British thermal units (“MMBtu”) amounts). Our financial information for the Gathering segment includes the results of the crude oil and natural gas gathering systems acquired in the Rockies Natural Gas Business Acquisition for the three and six months ended June 30, 2015.

Management uses average revenue per barrel and average revenue per MMBtu to evaluate performance and compare profitability to other companies in the industry. There are a variety of ways to calculate average revenue per barrel and average revenue per MMBtu; other companies may calculate these in different ways. We calculate average revenue per barrel as revenue divided by total throughput (barrels). We calculate average revenue per MMBtu as revenue divided by total throughput (MMBtu). Investors and analysts use these financial measures to help analyze and compare companies in the industry on the basis of operating performance. These financial measures should not be considered as an alternative to segment operating income, revenues and operating expenses or any other measure of financial performance presented in accordance with U.S. GAAP.



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues
Crude oil gathering pipeline revenues	$	30	$	13	$	57	$	25
Crude oil gathering trucking revenues	13		14		27		27
Gas gathering revenues (a)	46		—		82		—
Total Revenues	89		27		166		52
Costs and Expenses
Operating and maintenance expenses (b)	24		14		47		25
General and administrative expenses	3		—		6		1
Depreciation and amortization expenses	17		1		34		3
Total Costs and Expenses	44		15		87		29
Gathering Segment Operating Income	$	45	$	12	$	79	$	23
Volumes
Crude oil gathering pipeline throughput (bpd)	186,815		108,848		173,337		103,449
Average crude oil gathering pipeline revenue per barrel	$	1.71	$	1.34	$	1.80	$	1.34
Crude oil gathering trucking volume (bpd)	45,459		46,884		45,691		45,798
Average crude oil gathering trucking revenue per barrel	$	3.32	$	3.23	$	3.28	$	3.21
Gas gathering throughput (thousands of MMBtu/d) (a)	1,071		—		1,046		—
Average gas gathering revenue per MMBtu	$	0.48	$	—	$	0.43	$	—

_____________


(a)	Natural gas gathering revenues and volumes relate to the operations acquired in the Rockies Natural Gas Business Acquisition.


(b)	Operating and maintenance expenses include imbalance settlement gains of $1 million and $2 million for the three months ended June 30, 2015 and 2014, respectively and $2 million and $3 million for the six months ended June 30, 2015 and 2014, respectively.

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Volumes. Average crude oil gathering pipeline throughput volumes increased 77,967 bpd, or 72%, in the 2015 Quarter as a result of the expansion of our High Plains System and the Rockies Natural Gas Assets, including an 83,830 bpd increase in third-party volumes, offset by a 5,863 bpd decrease in affiliate volumes. Crude oil gathering trucking throughput volumes decreased 1,425 bpd, or 3%, during the 2015 Quarter due to lower demand. Average gas gathering throughput volumes were 1,071 thousand MMBtu/d for the 2015 Quarter, which contributed approximately 52% of total Gathering segment revenue.

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Financial Results. Gathering revenues increased $62 million, or 230%, to $89 million for the 2015 Quarter compared to $27 million in the 2014 Quarter primarily due to the Rockies Natural Gas Assets as well as higher crude oil pipeline throughput driven by our High Plains Pipeline reversal project. Average crude oil gathering trucking revenue per barrel increased in the 2015 Quarter relative to the 2014 Quarter due, in part, to higher fees collected for longer distance hauls, as well as a general increase in market rates.

Operating and maintenance expenses increased $10 million, or 71%, to $24 million in the 2015 Quarter compared to $14 million in the 2014 Quarter primarily related to higher costs associated with the Rockies Natural Gas Assets as well as the increased throughput on the High Plains System.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Volumes. Average crude oil gathering pipeline throughput volumes increased 69,888 bpd, or 68%, in the 2015 Period as a result of the expansion of our High Plains System and the Rockies Natural Gas Assets. This increase was almost entirely due to third-party volumes. Crude oil gathering trucking throughput volumes decreased 107 bpd during the 2015 Period due to lower demand. Average gas gathering throughput volumes were 1,046 thousand MMBtu/d for the 2015 Period, which contributed approximately 49% of total Gathering segment revenue.

Financial Results. Gathering revenues increased $114 million, or 219%, to $166 million for the 2015 Period compared to $52 million in the 2014 Period primarily as a result of the Rockies Natural Gas Assets as well as higher crude oil pipeline throughput driven by our High Plains Pipeline reversal project, increased third-party volumes and higher utilization of our proprietary trucking fleet. Average crude oil gathering trucking revenue per barrel increased in the 2015 Period relative to the 2014 Period due, in part, to higher fees collected for longer distance hauls, as well as a general increase in market rates.

Operating and maintenance expenses increased $22 million, or 88%, to $47 million in the 2015 Period compared to $25 million in the 2014 Period primarily related to higher costs associated with the Rockies Natural Gas Assets as well as the increased throughput on the High Plains System.

Processing Segment

The following table and discussion is an explanation of our results of operations of the Processing segment for the three and six months ended June 30, 2015 (in millions, except MMBtu/d, bpd and revenue per MMBtu and fee per barrel). The Processing segment was added as a result of the Rockies Natural Gas Business Acquisition on December 2, 2014, which included natural gas processing operations. Therefore, there was no activity to report for the processing segment for the three and six months ended June 30, 2014.

Management uses average revenue per MMBtu and average keep-whole fee per barrel to evaluate performance and compare profitability to other companies in the industry. There are a variety of ways to calculate average revenue per MMBtu and average keep-whole fee per barrel; other companies may calculate these in different ways. We calculate average revenue per MMBtu as revenue divided by total throughput (MMBtu). We calculate average keep-whole fee per barrel as revenue divided by total throughput (barrels). Investors and analysts use these financial measures to help analyze and compare companies in the industry on the basis of operating performance. These financial measures should not be considered as an alternative to segment operating income, revenues and operating expenses or any other measure of financial performance presented in accordance with U.S. GAAP.

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	Three Months Ended June 30,		Six Months Ended June 30,
	2015		2015
Revenues
NGL processing revenues	$	25	$	45
Fee-based processing revenues	24		53
Other processing revenues	18		36
Total Revenues	67		134
Costs and Expenses
Operating and maintenance expenses	30		60
General and administrative expenses	2		4
Depreciation and amortization expenses	11		22
Total Costs and Expenses	43		86
Processing Segment Operating Income	$	24	$	48
Volumes
NGL processing throughput (bpd)	7,796		7,366
Average keep-whole fee per barrel of NGL	$	35.14	$	33.60
Fee-based processing throughput (thousands of MMBtu/d)	768		729
Average fee-based processing revenue per MMBtu	$	0.36	$	0.40

Three Months Ended June 30, 2015

Volumes. Average fee-based processing volumes were 767,977 MMBtu/d and average NGL processing volumes totaled 7,796 bpd for the 2015 Quarter.

Financial Results. Total processing revenues were $67 million contributing approximately 24% to the Partnership’s total revenues for the 2015 Quarter. Operating and maintenance expenses were $30 million in the 2015 Quarter, which represents approximately 32% of total operating and maintenance expenses for the 2015 Quarter.

Six Months Ended June 30, 2015

Volumes. Average fee-based processing volumes were 728,846 MMBtu/d and average NGL processing volumes totaled 7,366 bpd for the 2015 Period.

Financial Results. Total processing revenues were $134 million contributing approximately 25% to the Partnership’s total revenues for the 2015 Period. Operating and maintenance expenses were $60 million in the 2015 Period, which represents approximately 33% of total operating and maintenance expenses for the 2015 Period.

Terminalling and Transportation Segment

The following tables and discussion are an explanation of our results of operations of the Terminalling and Transportation segment for the three and six months ended June 30, 2015 and 2014 (in millions, except barrel and per barrel amounts). Our financial information includes the historical results of our Predecessor and the results of TLLP for the three and six months ended June 30, 2014. See “Factors Affecting the Comparability of Our Financial Results” in our Annual Report on Form 10-K for the year ended December 31, 2014.

Management uses average revenue per barrel to evaluate performance and compare profitability to other companies in the industry. There are a variety of ways to calculate average revenue per barrel; other companies may calculate it in different ways. We calculate average revenue per barrel as revenue divided by total throughput (barrels). Investors and analysts use this financial measure to help analyze and compare companies in the industry on the basis of operating performance. This financial measure should not be considered as an alternative to segment operating income, revenues and operating expenses or any other measure of financial performance presented in accordance with U.S. GAAP.

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues			(Includes Predecessor)				(Includes Predecessor)
Terminalling revenues (a)	$	92	$	79	$	182	$	155
Pipeline transportation revenues	27		27		56		53
Total Revenues	119		106		238		208
Costs and Expenses
Operating and maintenance expenses (b)	40		41		73		75
General and administrative expenses	8		9		16		14
Depreciation and amortization expenses	16		16		32		30
Net gain on asset disposals and impairments	—		—		—		(4		)
Total Costs and Expenses	64		66		121		115
Terminalling and Transportation Operating Income	$	55	$	40	$	117	$	93
Volumes
Terminalling throughput (bpd)	912,881		913,355		915,202		907,375
Average terminalling revenue per barrel (a)	$	1.10	$	0.95	$	1.10	$	0.94
Pipeline transportation throughput (bpd)	800,971		812,649		809,596		814,901
Average pipeline transportation revenue per barrel	$	0.38	$	0.36	$	0.38	$	0.36

____________


(a)	Our Predecessor did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment for the West Coast Logistics Assets prior to the effective date of each acquisition with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.


(b)	Operating and maintenance expenses include imbalance settlement gains of $1 million for both of the three months ended June 30, 2015 and 2014 and $2 million for both of the six months ended June 30, 2015 and 2014.

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Volumes. Terminalling throughput volumes decreased 474 bpd in the 2015 Quarter compared to the 2014 Quarter primarily due to lower volumes at our Salt Lake City terminal. Pipeline transportation throughput volumes decreased 11,678 bpd in the 2015 Quarter compared to the 2014 Quarter primarily due to extended maintenance at Tesoro’s Utah refinery, which more than offset increased volumes from the refined products pipleine acquired as part of the West Coast Logistics Assets Acquisition.

Financial Results. Revenues increased $13 million, or 12%, to $119 million in the 2015 Quarter compared to $106 million in the 2014 Quarter primarily as a result of the commercial agreements executed with Tesoro at the time of the West Coast Logistics Assets Acquisition.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Volumes. Terminalling throughput volumes increased 7,827 bpd in the 2015 Period compared to the 2014 Period primarily as a result of higher volumes at our southern California terminals, which was partially offset by lower volumes at our Salt Lake City terminal. Pipeline transportation throughput volumes decreased 5,305 bpd in the 2015 Period compared to the 2014 Period due to planned maintenance at Tesoro’s Utah refinery.

Financial Results. Revenues increased $30 million, or 14%, to $238 million in the 2015 Period compared to $208 million in the 2014 Period primarily as a result of the higher volumes at our southern California terminals and the commercial agreements executed with Tesoro at the time of the West Coast Logistics Assets Acquisition.

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CAPITAL RESOURCES AND LIQUIDITY

Our primary cash requirements relate to funding capital expenditures, meeting operational needs and paying distributions to our unitholders. We expect our ongoing sources of liquidity to include cash generated from operations, reimbursement for certain maintenance and expansion expenditures, borrowings under the revolving credit facility (the “Revolving Credit Facility”) and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital, long-term capital expenditure, acquisition and debt servicing requirements and allow us to fund at least the minimum quarterly cash distributions.

ATM Program. On June 25, 2014, we filed a prospectus supplement to our shelf registration statement filed with the Securities and Exchange Commission in 2012 (“2012 Shelf”), authorizing the continuous issuance of up to an aggregate of $200 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “ATM Program”). During the three and six months ended June 30, 2015, we issued an aggregate of 373,014 and 819,513 common units, respectively, under our ATM Program, generating net proceeds of approximately $21 million and $45 million, respectively. The net proceeds from sales under the ATM Program will be used for general partnership purposes. We paid fees of $0.7 million and $1.2 million related to the issuance of units under the ATM Program for the three and six months ended June 30, 2015, respectively. The 2012 Shelf expired in June 2015, ending the issuance of units under our ATM Program.

Cash Distributions



Quarter Ended	Total Quarterly Distribution Per Unit		Total Quarterly Distribution Per Unit, Annualized		Total Cash Distribution including general partner IDRs (in millions)		Date of Distribution	Unitholders Record Date
December 31, 2014	$	0.6675	$	2.67	$	70	February 13, 2015	February 2, 2015
March 31, 2015	0.6950		2.78		70		May 15, 2015	May 4, 2015
June 30, 2015 (a)	0.7225		2.89		81		August 14, 2015	August 3, 2015

____________

(a) This distribution was declared on July 23, 2015 and will be paid on the date of distribution.

In connection with the Rockies Natural Gas Business Acquisition, our general partner has waived its right to $10 million of general partner distributions with respect to IDRs during 2015 (pro rata on a quarterly basis).

Debt Overview

Our debt net of unamortized issuance costs of $2.6 billion, at June 30, 2015 is summarized as follows (in millions):



Debt principal, including current maturities:	June 30, 2015
Revolving Credit Facility	$	299
5.500% Senior Notes due 2019	500
5.875% Senior Notes due 2020	470
6.125% Senior Notes due 2021	550
6.250% Senior Notes due 2022	800
Capital lease obligations	8
Total Debt	2,627
Unamortized Issuance Costs (b)	(41		)
Debt, Net of Unamortized Issuance Costs	$	2,586

____________

(b) Includes unamortized premium associated with our 5.875% Senior Notes due 2020 of $4 million as of June 30, 2015.

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Revolving Credit Facility

As of June 30, 2015, our Revolving Credit Facility provided for total loan availability of $900 million, and we are allowed to request that the loan availability be increased up to an aggregate of $1.5 billion, subject to receiving increased commitments from the lenders. Our Revolving Credit Facility is non-recourse to Tesoro, except for TLGP, and is guaranteed by all of our consolidated subsidiaries, with the exception of Rendezvous Gas Services L.L.C., and secured by substantially all of our assets. Borrowings are available under the Revolving Credit Facility up to the total loan availability of the facility. We had $299 million of borrowings outstanding under the Revolving Credit Facility, resulting in a total unused loan availability of $601 million or 67% of the borrowing capacity as of June 30, 2015. The weighted average interest rate for borrowings under our Revolving Credit Facility was 2.75% at June 30, 2015. The Revolving Credit Facility is scheduled to mature on December 2, 2019.

The Revolving Credit Facility was subject to the following expenses and fees at June 30, 2015:



Credit Facility	30 day Eurodollar (LIBOR) Rate	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (c)	0.19%	2.50%	3.25%	1.50%	0.50%

____________

(c) We have the option to elect if the borrowings will bear interest at either a base rate plus the base rate margin, or a Eurodollar rate, for the applicable period, plus the Eurodollar margin at the time of the borrowing. The applicable margin varies based upon a certain leverage ratio, as defined by the Revolving Credit Facility. We also incur commitment fees for the unused portion of the Revolving Credit Facility at an annual rate. Letters of credit outstanding under the Revolving Credit Facility incur fees at the Eurodollar margin rate.

The Revolving Credit Facility and our Senior Notes due 2019, 2020, 2021 and 2022 contain covenants that may, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to engage in certain activities. There have been no changes in these covenants from those described in the Annual Report on 10-K for the year ended December 31, 2014. We do not believe that these limitations will restrict our ability to pay distributions. Additionally, the Revolving Credit Facility contains covenants that require us to maintain certain interest coverage and leverage ratios. We submit compliance certifications to the bank quarterly, and we were in compliance with our debt covenants as of June 30, 2015.

Cash Flow Summary

Components of our cash flows are set forth below (in millions):



	Six Months Ended June 30,
	2015			2014
Cash Flows From (Used In):
Operating Activities	$	222		$	86
Investing Activities	(166		)	(54		)
Financing Activities	(62		)	(54		)
Decrease in Cash and Cash Equivalents	$	(6	)	$	(22	)

Operating Activities. Net cash from operating activities increased $136 million to $222 million in the 2015 Period compared to $86 million for the 2014 Period primarily due to a significant contribution of operating income from the Rockies Natural Gas Business Acquisition as well as incremental cash flow from growth on the High Plains System and commercial agreements executed in connection with the West Coast Logistics Assets Acquisition.

Investing Activities. Net cash used in investing activities for the 2015 Period increased $112 million to $166 million compared to $54 million in the 2014 Period. The increase related to this outflow was a result of higher capital expenditures in the 2015 Period including spending related to the construction of the Connolly Gathering System, the second phase of the Bakken area storage hub, and various projects on our Southern California distribution system. See “Capital Expenditures” below for a discussion of the various maintenance and growth projects in the 2015 Period, including those reimbursed by our customers.

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Financing Activities. Net cash used in financing activities for the 2015 Period was $62 million compared to $54 million for the 2014 Period. We paid higher quarterly cash distributions totaling $140 million during the 2015 Period compared to quarterly cash distributions totaling $75 million paid in the 2014 Period. Additionally, we paid $18 million in distributions to the common public unitholders of QEPM and QEPM’s subsidiaries during the 2015 Period. Cash distributions were offset by proceeds from the issuance of units under our ATM program of $45 million and $39 million of net borrowings under our Revolving Credit Facility during the 2015 Period.

Capital Expenditures

The Partnership’s operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to maintain assets, ensuring regulatory compliance. The cost estimates described below are subject to further review, analysis and permitting requirements and include estimates for capitalized interest and labor. Maintenance capital expenditures include expenditures required to maintain equipment reliability and integrity and to address regulatory compliance. Growth capital expenditures include expenditures to purchase or construct new assets and to expand existing facilities or services that may increase throughput capacity on our pipelines, in our terminals and at our processing facilities, increase storage capacity, increase well connections and compression as well as other services at our facilities.

The following table is a summary of our capital expenditures for the three and six months ended June 30, 2015 and 2014 (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Growth	$	62	$	43	$	119	$	67
Maintenance	15		5		24		7
Total Capital Expenditures	$	77	$	48	$	143	$	74

The following table is a summary of our total 2015 expected capital expenditures, 2015 Period capital expenditures and estimated remaining capital expenditures, presented both gross and net of reimbursements (in millions):



	Total 2015 Expected Capital Expenditures		Total 2015 Expected Capital Expenditures, Net		2015 Period Capital Expenditures		2015 Period Capital Expenditures, Net		Remaining 2015 Capital Expenditures		Remaining 2015 Capital Expenditures, Net
Growth	$	390	$	380	$	119	$	110	$	271	$	270
Maintenance	60		40		24		21		36		19
Total Capital Expenditures	$	450	$	420	$	143	$	131	$	307	$	289

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Growth Capital Expenditures

Major projects include the following:

•

Connolly Gathering System construction with estimated capital spending of $150 million, with current year spending expected to be approximately $115 million. The Connolly Gathering System will gather crude oil from various points in Dunn County, North Dakota for delivery at the existing Connolly Station and is expected to have a capacity of approximately 60,000 bpd. The first barrels were delivered into the main line at the end of 2014. In the 2015 Period we spent $54 million related to the Connolly Gathering System.

•

The construction of the second phase of the Bakken Area Storage Hub (“BASH”) with 2015 expected spending of $30 million. The BASH provides storage for the Bakken region with tanks located in two strategic areas of the basin. It has current storage capacity of approximately 780,000 barrels, growing to over 1 million barrels of capacity by the end of 2015. We spent $9 million during the 2015 Period on the second phase of this project.


•	Projects to expand and optimize the southern California distribution system with 2015 expected spending of $25 million. The projects are expected to increase throughput and expand ancillary service capabilities. We spent $12 million during the 2015 Period on the southern California distribution system projects.


•	A new light products truck rack at the site of the existing Anacortes terminal acquired as part of the West Coast Logistics Assets, which is expected to add an additional 6,000 to 7,000 barrels per day of gasoline and diesel throughput. The project has a total capital spend of $23 million and is expected to be operational in the second half of 2015.


•	Projects to increase compression for our Pinedale and Uinta natural gas gathering systems and expand our gathering system in the Uinta basin with estimated capital spending of $35 million to $45 million in 2015.


•	Projects to expand crude oil gathering throughputs on the High Plains Pipeline in McKenzie County, ND.

Environmental and Other Matters

Environmental Regulation

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to remediate environmental damage from any discharge of petroleum, natural gas or chemical substances from our facilities or require us to install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil, or criminal penalties, the imposition of investigatory and remedial liabilities and the issuance of injunctions that may subject us to additional operational constraints.

Future expenditures may be required to comply with the federal, state and local environmental requirements for our various sites, including our storage facilities, pipelines, gas processing complexes and refined products terminals. The impact of these legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our liquidity, financial position or results of operations. Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of our initial public offering in April 2011 (“Initial Offering”) and subsequent acquisitions from Tesoro.

Environmental Liabilities

Contamination resulting from spills of crude oil, natural gas and refined products is not unusual within the terminalling, pipeline, gathering or processing industries. Historic spills at certain of our assets as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at our properties where releases of hydrocarbons and other wastes have occurred. A number of our properties have known hydrocarbon or other hazardous material contamination in the soil and groundwater. See below for our discussion of the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement for more information regarding the indemnification of certain environmental matters provided to us by Tesoro and discussion of certain environmental obligations that were retained by Chevron Pipe Line Company and Northwest Terminalling Company (collectively, “Chevron”) in conjunction with the acquisition of the northwest products system (the “Northwest Products System”).

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The Partnership has been party to various environmental matters arising in the ordinary course of business. The outcome of these matters cannot always be accurately predicted, but the Partnership recognizes liabilities for these matters based on estimates and applicable accounting guidelines and principles. We have accrued liabilities for these expenses and believe these accruals are adequate based on current information and projections that can be reasonably estimated. Our environmental liabilities are estimates using internal and third-party assessments and available information to date. It is possible that these estimates will change as more information becomes available. Our accruals for these environmental expenditures totaled $22 million and $32 million at June 30, 2015 and December 31, 2014, respectively.

Chevron Diesel Pipeline Release. On March 18, 2013, Chevron Pipe Line Company and Northwest Terminalling Company (collectively, “Chevron”) detected and responded to the release of diesel fuel (the “Diesel Pipeline Release”) that occurred near Willard, Utah on the Northwest Products System. As a result of this release, a Corrective Action Order (the “CAO”) was issued on March 22, 2013 by PHMSA. The Partnership assumed responsibility for performing additional testing and associated pipeline repairs on the pipeline pursuant to the CAO upon closing the Northwest Products System acquisition. On March 6, 2015, PHMSA issued a closure letter indicating that we have complied with all the terms of the CAO and that no further action is required.

Other Environmental Spending

We completed a detailed inspection and maintenance program in the 2015 Period, which included spending of $22 million inception to date to perform inspections and repairs that improved the integrity of the Northwest Products System. This included the costs to comply with the CAO and also costs expected for inspections and repairs on other sections of the pipeline. The purchase price of the Northwest Products system was reduced by $45 million to compensate the Partnership for assuming responsibilities under the CAO and to perform additional inspection and maintenance as the Partnership deemed necessary.

Tesoro Indemnification

Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and subsequent acquisitions from Tesoro. See Note 11 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of the Amended Omnibus Agreement.

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Legal

Questar Gas Company v. QEP Field Services Company. QEPFS’ former affiliate, Questar Gas Company (“QGC”) and its affiliate Wexpro, filed a complaint 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. Tesoro Logistics has agreed to indemnify QEP Field Services Company (“QEPFSC”) for this claim under the acquisition agreement for QEPFS. Under the 1993 Agreement, certain of QEPFS’ systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service calculation. QGC is disputing the annual calculation of the gathering rate, which has been calculated in the same manner since 1998, without objection by QGC. At the closing of the QEPM initial public offering (“QEPM IPO”), the assets and agreement discussed above were assigned to QEPM. QGC amended its complaint to add QEPM as a defendant in the litigation. QEPM was indemnified by the Partnership upon closing of the Rockies Natural Gas Business Acquisition for costs, expenses and other losses incurred by QEPM in connection with the QGC dispute, subject to certain limitations, as set forth in the QEPM Omnibus Agreement. QGC has netted $17 million of disputed amounts from its monthly payments of the gathering fees to QEPFS and has continued to net such amounts from its monthly payment to QEPM. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. As a result of the summary judgment, the Partnership assumed a $21 million liability for estimated damages in excess of the amount QGC has netted for disputed amounts. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits. We believe the outcome of this matter will not have a material impact on our liquidity, financial position, or results of operations.

Other than described above, we did not have any material outstanding lawsuits, administrative proceedings or governmental investigations as of June 30, 2015.

IMPORTANT INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (including information incorporated by reference) includes and references “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These statements relate to, among other things, expectations regarding revenues, cash flows, capital expenditures and other financial items. These statements also relate to our business strategy, goals and expectations concerning our market position, future operations and profitability. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will,” “would” and similar terms and phrases to identify forward-looking statements in this Quarterly Report on Form 10-Q, which speak only as of the date the statements were made.

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Although we believe the assumptions upon which these forward-looking statements are based are reasonable, any of these assumptions could prove to be inaccurate and the forward-looking statements based on these assumptions could be incorrect. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results and trends to differ materially from those made, projected, or implied in or by the forward-looking statements depending on a variety of uncertainties or other factors including, but not limited to:


•	the suspension, reduction or termination of our customer’s obligation under commercial agreements or our secondment agreement;


•	changes in global economic conditions and the effects of a global economic downturn on Tesoro’s business and the business of its suppliers, customers, business partners and credit lenders;


•	a material decrease in Tesoro’s profitability;


•	a material decrease in the crude oil and natural gas produced in the Bakken Region;


•	a material decrease in the natural gas produced in the Rockies Region;


•	disruptions due to equipment interruption or failure at our facilities, Tesoro’s facilities or third-party facilities on which Tesoro’s business is dependent;


•	changes in the expected value of and benefits derived from acquisitions, including the Rockies Natural Gas Business acquisition;


•	impact of QEP Resources’ and Questar Gas Company’s failure to perform under the terms of our gathering agreements as they are our largest customers in TLLP’s natural gas business;


•	the risk of contract cancellation, non-renewal or failure to perform by Tesoro’s customers and Tesoro’s inability to replace such contracts and/or customers;


•	Tesoro’s ability to remain in compliance with the terms of its outstanding indebtedness;


•	the timing and extent of changes in commodity prices and demand for refined products, natural gas and NGLs;


•	actions of customers and competitors;


•	changes in our cash flow from operations;


•	state and federal environmental, economic, health and safety, energy and other policies and regulations, including those related to climate change and any changes therein and any legal or regulatory investigations, delays or other factors beyond our control;


•	operational hazards inherent in refining operations and in transporting and storing crude oil, natural gas, NGLs and refined products;


•	earthquakes or other natural disasters affecting operations;


•	changes in capital requirements or in execution of planned capital projects;


•	the availability and costs of crude oil, other refinery feedstocks and refined products;


•	changes in the cost or availability of third-party vessels, pipelines and other means of delivering and transporting crude oil, feedstocks and refined products;


•	direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war;


•	weather conditions affecting our or Tesoro’s operations or the areas in which Tesoro markets its refined products;

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•	seasonal variations in demand for refined products;


•	adverse rulings, judgments, or settlements in litigation or other legal or tax matters, including unexpected environmental remediation costs in excess of any accruals, which affect us or Tesoro;


•	risks related to labor relations and workplace safety;


•	changes in insurance markets impacting costs and the level and types of coverage available;


•	the coverage and ability to recover claims under our insurance policies; and


•	political developments.

Many of these factors, as well as other factors, are described in our filings with the SEC. All future written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the previous statements. We undertake no obligation to update any information contained herein or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this Quarterly Report on Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. As we do not own the refined products, natural gas or crude oil that are shipped through our pipelines, distributed through our terminals or held in our storage facilities we have minimal direct exposure to risks associated with fluctuating commodity prices. In addition, our commercial agreements with Tesoro are indexed for inflation and contain fuel surcharge provisions that are designed to substantially mitigate our exposure to increases in diesel fuel prices and the cost of other supplies used in our business. We do not intend to hedge our exposure to commodity price risk related to imbalance gains and losses or to diesel fuel or other supply costs.

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 revenue is dependent on 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. We do not enter into commodity derivative instruments because of the minimal impact of commodity price risk on our liquidity, financial position and results of operations. Assuming all other factors remained constant a $1 change in condensate pricing, based on our quarter-to-date average throughput, would be immaterial to our consolidated operating income. This analysis may differ from actual results.

Effective December 2, 2014, following the completion of the Rockies Natural Gas Business Acquisition, we began processing gas for certain producers under “keep-whole” processing agreements. Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a British thermal unit content equivalent to the NGLs removed. The operating margin for these contracts is determined by the spread between NGL sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). TLLP entered into a five-year agreement with Tesoro, which transfers the commodity risk exposure associated with these keep-whole processing agreements from TLLP to Tesoro. Under the Keep-Whole Commodity Agreement with Tesoro, Tesoro pays TLLP a processing fee for NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of TLLP. TLLP pays Tesoro a marketing fee in exchange for assuming the commodity risk.

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Interest Rate Risk

Our use of debt directly exposes us to interest rate risk. Variable-rate debt, such as borrowings under our Revolving Credit Facility, exposes us to short-term changes in market rates that impact our interest expense. Fixed rate debt, such as our Senior Notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to rates higher than the current market. The fair value of our fixed rate debt was estimated using quoted market prices. The carrying value of our debt was approximately $2.6 billion and the fair value of our debt was approximately $2.7 billion as of June 30, 2015. The carrying value and fair value of our debt were both approximately $2.6 billion as of December 31, 2014. These carrying and fair values of our debt do not include the unamortized issuance costs associated with our total debt. Unless interest rates increase significantly in the future, our exposure to interest rate risk should be minimal. With all other variables constant, a 0.25% change in the interest rate associated with the borrowings outstanding under our Revolving Credit Facility at June 30, 2015 would change annual interest expense by less than $1 million. As of June 30, 2015, we had $299 million of borrowings under our Revolving Credit Facility. Any change in interest rates would affect cash flows, but not the fair value of the debt we incur under our Revolving Credit Facility.

We do not currently have in place any hedges or forward contracts to reduce our exposure to interest rate risks; however, we continue to monitor the market and our exposure, and may enter into these transactions in the future. We believe in the short-term we have acceptable interest rate risk and continue to monitor the risk on our long-term obligations.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that the information that we are required to disclose in reports we file under the Securities Exchange Act of 1934, as amended (“the Exchange Act”), is accumulated and appropriately communicated to management. In 2014, we completed a transition from the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework for assessing our internal control effectiveness over financial reporting. There have been no significant changes in our internal controls over financial reporting (as defined by applicable Securities and Exchange Commission rules) during the quarter ended June 30, 2015 that have materially affected or are reasonably likely to materially affect these controls.

We carried out an evaluation required by Rule 13a-15(b) of the Exchange Act, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures at the end of the reporting period. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Although we cannot provide assurance, we do not believe we are a party to any litigation that will have a material adverse impact on our liquidity, consolidated financial position, or results of operations. There were no new proceedings or material developments in proceedings that were previously reported in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 1A. RISK FACTORS

There have been no significant changes from the risk factors previously disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014.

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

We may acquire units to satisfy tax withholding obligations in connection with the vesting of units issued to certain employees. There were no such units acquired during the three months ended June 30, 2015.

ITEM 5. OTHER INFORMATION

Termination of the First Amended and Restated Omnibus Agreement of QEPM

QEPM amended and restated its omnibus agreement upon closing of the Rockies Natural Gas Business Acquisition on December 2, 2014 (“QEPM Omnibus Agreement”) to transfer all previous rights and obligations to TLLP and TLGP, as outlined in the QEPM Omnibus Agreement. Under the QEPM Omnibus Agreement, TLLP indemnified QEPM for certain matters, including legal, environmental, title and tax matters associated with the ownership of the acquired assets at or before the closing of QEPM’s initial offering on August 14, 2013. On August 3, 2015, subsequent to the Merger, TLLP and QEPM terminated the QEPM Omnibus Agreement.

Amendment No. 2 to the Third Amended and Restated Omnibus Agreement

As a result of the termination of the QEPM Omnibus Agreement on August 3, 2015, as discussed above, Tesoro, TRMC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, TLLP and TLGP entered into an amendment to the Third Amended and Restated Omnibus Agreement. The amendment, effective July 1, 2015, increases the annual administrative fee payable by the Partnership to Tesoro by $3.6 million as a result of the merger of TLLP and QEPM and the termination of the QEPM Omnibus Agreement. The annual increase accounts for the additional fixed costs and expenses related to the administration of the assets of QEPM and its subsidiaries that was previously payable under the QEPM Omnibus Agreement.

Termination of the Affiliate Credit Agreement

On December 2, 2014, in connection with the Rockies Natural Gas Business Acquisition, we entered into the unsecured Affiliate Credit Agreement (the “Affiliate Credit Agreement”), in which QEPFS agreed to provide revolving loans and advances to QEPM up to a borrowing capacity of $500 million. On August 3, 2015, after completion of the Merger, the Affiliate Credit Agreement was terminated by converting the outstanding borrowings of $203 million into an additional QEPFS limited partner interest in QEPM.

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ITEM 6. EXHIBITS

(a)Exhibits



Exhibit Number		Description of Exhibit

2.1		Agreement and Plan of Merger, dated as of April 6, 2015, by and among Tesoro Logistics LP, Tesoro Logistics GP, LLC, QEP Field Services, LLC, TLLP Merger Sub LLC, QEP Midstream Partners, LP, and QEP Midstream Partners GP, LLC (incorporated by reference herein to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on April 6, 2015, File 1-35143).

*4.1		Second Supplemental Indenture, dated as of May 21, 2015, among TLLP Merger Sub LLC, Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 5.50% Senior Notes due 2019 and the 6.25% Senior Notes due 2022.

*4.2		Fourth Supplemental Indenture, dated as of May 21, 2015, among TLLP Merger Sub LLC, Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 6.125% Senior Notes due 2021.

*4.3		Sixth Supplemental Indenture, dated as of May 21, 2015, among TLLP Merger Sub LLC, Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 5.875% Senior Notes due 2020.

10.1		Support Agreement, dated as of April 6, 2015 by and among QEP Midstream Partners, LP, Tesoro Logistics LP, and QEP Field Services, LLC (incorporated by reference herein to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on April 6, 2015, File 1-35143).

10.2		Tesoro Logistics LP Non-Employee Director Compensation Program. (incorporated by reference herein to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on May 8, 2015, File 1-35143)

*10.3		Amendment No. 2 to the Third Amended and Restated Omnibus Agreement, dated as of August 3, 2015, among Tesoro Corporation, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Tesoro Logistics LP and Tesoro Logistics GP, LLC.

*10.4		Termination of First Amended and Restated Omnibus Agreement, dated as of August 3, 2015, among Tesoro Logistics LP and Tesoro Logistics GP, LLC, QEP Midstream Partners GP, LLC, QEP Midstream Partners, LP, and QEP Midstream Partners Operating, LLC.

*10.5		Termination of Credit Agreement, dated as of August 3, 2015, between QEP Field Services, LLC and QEP Midstream Partners, LP.

*31.1		Certification by Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification by Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		XBRL Taxonomy Extension Label Linkbase Document

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

____________


*	Filed herewith


**	Submitted electronically herewith

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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 hereunto duly authorized.



		TESORO LOGISTICS LP

		By:	Tesoro Logistics GP, LLC
			Its general partner

Date:	August 6, 2015	By:	/s/ GREGORY J. GOFF
			Gregory J. Goff
			Chief Executive Officer
			(Principal Executive Officer)

Date:	August 6, 2015	By:	/s/ STEVEN M. STERIN
			Steven M. Sterin
			Vice President and Chief Financial Officer
			(Principal Financial Officer)

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NON WHOLLY-OWNED GUARANTOR SUBSIDIARY FINANCIAL STATEMENTS

(Unaudited)

Tesoro Logistics LP (“TLLP”) is required to provide stand-alone financial statements for its non wholly-owned guarantor subsidiaries, QEPM and Green River Processing, LLC (“Green River Processing”), pursuant to Rule 3-10 of Regulation S-X. At June 30, 2015, TLLP and certain subsidiary guarantors have fully and unconditionally guaranteed TLLP’s registered 2020 Senior Notes and 2021 Senior Notes. QEP Field Services, LLC (“QEPFS”) and certain of its subsidiaries, including QEPM and Green River Processing, were elected guarantors of these obligations in January 2015. Stand-alone financial statements for QEPM and Green River Processing are as follows:

QEP MIDSTREAM PARTNERS, LP

AND

GREEN RIVER PROCESSING, LLC

INDEX TO FINANCIAL STATEMENTS



QEP MIDSTREAM PARTNERS, LP FINANCIAL STATEMENTS		Page

PART I. FINANCIAL INFORMATION
QEP Midstream Partners, LP Financial Statements (Unaudited)		F-2
Condensed Statements of Consolidated Operations - Three and Six Months Ended June 30, 2015 and 2014		F-2
Condensed Consolidated Balance Sheets - June 30, 2015 and December 31, 2014		F-3
Condensed Statements of Consolidated Cash Flows - Six Months Ended June 30, 2015 and 2014		F-4
Notes to Condensed Consolidated Financial Statements		F-5
QEP Midstream Partners, LP Management's Discussion and Analysis of Financial Condition and Results of Operations		F-18

PART II. OTHER INFORMATION
Item 1. Legal Proceedings		F-25
Item 1A. Risk Factors		F-25
Item 2. Unregistered Sales of Equity Securities		F-25
Item 3. Quantitative and Qualitative Disclosures		F-25
Item 4. Controls and Procedures		F-26



GREEN RIVER PROCESSING, LLC FINANCIAL STATEMENTS	Page

Green River Processing, LLC Financial Statements (Unaudited)	F-27
Condensed Statements of Operations - Three and Six Months Ended June 30, 2015 and 2014	F-27
Condensed Balance Sheets - June 30, 2015 and December 31, 2014	F-28
Condensed Statements of Cash Flows - Six Months Ended June 30, 2015 and 2014	F-29
Notes to Condensed Financial Statements	F-30
Green River Processing, LLC Management's Discussion and Analysis of Financial Condition and Results of Operations	F-33

F-1

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QEP MIDSTREAM PARTNERS, LP

PART I. FINANCIAL INFORMATION

QEP Midstream Partners, LP Financial Statements

QEP MIDSTREAM PARTNERS, LP

CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions, except unit and per unit amounts)
Revenues
Gathering and transportation	$	33		$	28		$	66		$	57
Condensate sales	1			2			3			4
Total Revenues	34			30			69			61
Operating Expenses
Gathering expenses	8			7			14			13
General and administrative expenses	6			5			10			10
Depreciation and amortization expenses	8			8			16			16
Loss on asset impairments	5			—			5			—
Total Operating Expenses	27			20			45			39
Operating Income	7			10			24			22
Income from unconsolidated affiliates	7			—			13			2
Interest expense	(1		)	—			(2		)	(1		)
Net Income	13			10			35			23
Net income attributable to noncontrolling interest	(1		)	(1		)	(2		)	(2		)
Net Income Attributable to QEP Midstream	$	12		$	9		$	33		$	21

Net income attributable to QEP Midstream per limited partner unit:
Common - basic and diluted	$	0.24		$	0.18		$	0.61		$	0.39
Subordinated - basic and diluted	$	0.24		$	0.18		$	0.61		$	0.39

Weighted-average limited partner units outstanding:
Common units - basic	26,749,311			26,719,037			26,741,902			26,716,267
Common units - diluted	26,753,276			26,719,037			26,745,017			26,720,412
Subordinated units - basic and diluted	26,705,000			26,705,000			26,705,000			26,705,000
Cash distributions per unit (a)	$	—		$	0.28		$	0.32		$	0.55

_____________


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

See notes accompanying the unaudited condensed consolidated financial statements.

F-2

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QEP MIDSTREAM PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2015			December 31, 2014
	(In millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	6		$	15
Accounts receivable, net	22			20
Accounts receivable from affiliate	16			2
Total Current Assets	44			37
Property, Plant and Equipment, Net	459			476
Investment in Unconsolidated Affiliates	138			136
Total Assets	$	641		$	649

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	5		$	12
Accounts payable to affiliate	9			1
Other current liabilities	4			2
Total Current Liabilities	18			15
Affiliate Long-Term Debt	203			210
Other Long-Term Liabilities	24			25
Total Long-Term Liabilities	227			235
Commitments and Contingencies (see Note 6)
Equity
Limited partner common units; 26,753,205 units issued and outstanding (26,729,240 in 2014)	392			393
Limited partner subordinated units; 26,705,000 units issued and outstanding (26,705,000 in 2014)	(36		)	(36		)
General partner units; 1,090,495 units issued and outstanding (1,090,495 in 2014)	(1		)	(1		)
Total Partners’ Capital	355			356
Noncontrolling interest	41			43
Total Equity	396			399
Total Liabilities and Equity	$	641		$	649

See notes accompanying the unaudited condensed consolidated financial statements.

F-3

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QEP MIDSTREAM PARTNERS, LP

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2015			2014
	(In millions)
Cash Flows From (Used In) Operating Activities:
Net income	$	35		$	23
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization expenses	16			16
Loss on asset impairments	5			—
Equity-based compensation expense	—			1
Income from unconsolidated affiliates	(13		)	(2		)
Distributions from unconsolidated affiliates	13			4
Changes in current assets and current liabilities	(12		)	(6		)
Changes in non-current assets and non-current liabilities	(1		)	4
Net cash from operating activities	43			40
Cash Flows From (Used In) Investing Activities:
Capital expenditures	(4		)	(11		)
Contributions to unconsolidated affiliates	(3		)	—
Net cash used in investing activities	(7		)	(11		)
Cash Flows From (Used In) Financing Activities:
Borrowings under affiliate credit agreement	29			—
Repayments under affiliate credit agreement	(36		)	—
Contributions from parent, net	—			1
Distributions to unitholders	(34		)	(29		)
Distribution to noncontrolling interest	(4		)	(3		)
Net cash used in financing activities	(45		)	(31		)
Decrease In Cash and Cash Equivalents	(9		)	(2		)
Cash and Cash Equivalents, Beginning of Period	15			19
Cash and Cash Equivalents, End of Period	$	6		$	17

Supplemental Cash Flow Disclosure of Non-Cash Activities:
Change in capital expenditure accrual balance	$	(1	)	$	(3	)

See notes accompanying the unaudited condensed consolidated financial statements.

F-4

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION

References in this report to “QEP Midstream,” the “Partnership,” “we,” “our,” “us,” or like terms, refer to QEP Midstream Partners, LP and its subsidiaries. For purposes of these financial statements, “QEP Resources” refers to QEP Resources, Inc. and its consolidated subsidiaries, “TLLP” refers to Tesoro Logistics LP and its consolidated subsidiaries and “QEPFS” refers to QEP Field Services, LLC.

QEP Midstream and certain of its subsidiaries were elected guarantors of TLLP’s registered 2020 Senior Notes and 2021 Senior Notes in January 2015. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture.

Description of Business

QEP Midstream Partners, LP (“the Partnership”) is a Delaware limited partnership formed in April 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 August 2013, the Partnership completed its initial public offering (the “IPO”). As part of the IPO, QEP Midstream Partners GP, LLC (our “General Partner”) and QEP Field Services Company (“QEPFSC”), collectively contributed to the Partnership a 100% ownership interest in each of QEP Midstream Partners Operating, LLC (the “Operating Company”), QEPM Gathering I, LLC and Rendezvous Pipeline Company, LLC (“Rendezvous Pipeline”), a 78% interest in Rendezvous Gas Services, L.L.C. (“Rendezvous Gas”), and a 50% equity interest in Three Rivers Gathering, L.L.C. (“Three Rivers Gathering”). In July 2014, the Partnership acquired a 40% interest in Green River Processing, LLC (“Green River Processing”). Refer to Note 2 for further detail.

On December 2, 2014, QEP Resources’ midstream business was acquired by TLLP, which included all of the issued and outstanding membership interest of QEPFS, a wholly-owned subsidiary of QEPFSC formed for purposes of consummating the QEP Field Services acquisition. QEPFS is the owner of our General Partner, which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights (“IDRs”) as of June 30, 2015. The acquisition also included an approximate 56% limited partner interest in the Partnership (collectively, the “Acquisition”). Prior to this transaction, QEP Resources, through its wholly-owned subsidiary QEPFSC, owned and operated our General Partner, therefore, the Acquisition resulted in a change of control of our General Partner and the Partnership became a consolidated subsidiary of TLLP on the acquisition date.

On April 6, 2015, TLLP entered into an Agreement and Plan of Merger (the “Merger Agreement”) with TLGP, QEPFS, TLLP Merger Sub LLC (“Merger Sub”), QEP Midstream, and QEP Midstream Partners GP, LLC (“QEPM GP”). In July 2015, TLLP and QEP Midstream completed the transaction, in which the Merger Sub merged with and into QEP Midstream, with QEP Midstream surviving the merger as a wholly-owned subsidiary of TLLP (the “Merger”). Following the Merger, QEPM GP remains the general partner of QEP Midstream, and all outstanding common units representing limited partnership interests in QEP Midstream other than QEP Midstream Common Units held by QEPFS (the “QEPM Common Units”) were converted into the right to receive 0.3088 common units representing limited partnership interests in TLLP (the “TLLP Common Units”). The Merger was completed July 22, 2015 and TLLP issued approximately 7.1 million TLLP Common Units to QEPM unitholders. No fractional TLLP Common Units were issued in the Merger, and holders of QEPM Common Units other than QEPFS received cash in lieu of fractional TLLP Common Units.

Following the completion of the Merger, QEP Midstream notified the New York Stock Exchange (the “NYSE”) on July 22, 2015 that the Merger was effected and requested that the NYSE file a notification of removal from listing on Form 25 with the Securities and Exchange Commission with respect to the QEPM Common Units. The trading of QEPM Common Units on the NYSE was suspended from trading before the opening of the market on July 23, 2015, the first business day following the completion of the Merger.

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

The General Partner serves as general partner of the Partnership and, together with TLLP, provides services to the Partnership pursuant to the First Amended and Restated Omnibus Agreement (the “Amended Omnibus Agreement”), entered into in connection with the Acquisition. The Amended Omnibus Agreement, dated December 2, 2014, amended and restated the Omnibus Agreement dated August 14, 2013 (the “Original Omnibus Agreement”), entered into in connection with the closing of the IPO.

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 Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation.

Recent Accounting Developments

Pushdown Accounting. The Securities and Exchange Commission (the “SEC”) released a Staff Accounting Bulletin in November 2014, overturning portions of the interpretive guidance regarding pushdown accounting. Effective November 18, 2014, the new bulletin aligns the existing guidance to the ASU issued by the FASB in October 2014. Under the new guidance, pushdown accounting can be applied in the separate financial statements of the acquired entity upon completion of the acquisition or in a subsequent period. This impacts the stand-alone financial statements of the subsidiary, but does not alter the existing reporting requirements for the parent company to record the acquired assets, liabilities, and non-controlling interests in consolidated financial statements. If pushdown accounting is not applied in the reporting period in which the change-in-control event occurs, an acquired entity will have the option to elect to apply pushdown accounting in a subsequent reporting period. If pushdown accounting is applied, that election is irrevocable. The SEC responded by rescinding its guidance on pushdown accounting, which had required registrants to apply pushdown accounting in certain circumstances. With regard to the Acquisition, TLLP elected not to apply pushdown accounting to the Partnership.

Treatment of Predecessor in EPU calculation. In April 2015, the FASB issued ASU 2015-06, which requires a master limited partnership to allocate earnings or losses of transferred net assets for periods prior to asset purchases from an entity under common control entirely to the general partner when calculating earnings per unit (“EPU”). The ASU is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We elected to adopt this guidance beginning in the first quarter of 2015. The final ASU did not impact our EPU or related disclosure.

Debt Issuance Costs. In April 2015, the FASB issued Accounting Standard Update 2015-03, “Interest - Imputation of Interest” (“ASU 2015-03”), which will simplify the presentation of debt issuance costs. Under ASU 2015-03, debt issuance costs related to a recognized debt liability will be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability. As a result, our balance sheet will reflect a reclassification of unamortized debt issuance costs from other noncurrent assets to debt. ASU 2015-03 is effective for interim and annual periods beginning after December 15, 2015, and early adoption is permitted. We have adopted this standard effective as of March 31, 2015, and applied the changes retrospectively to prior periods presented. Adoption of this standard did not impact our financial statements or related disclosures for the periods presented, as there were no debt issuance costs recorded as of June 30, 2015 or December 31, 2014.

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 2 - ACQUISITION

Green River Processing Acquisition

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, a wholly-owned subsidiary of QEPFSC, from QEPFSC for $230 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 million of borrowings under the Partnership’s $500 million revolving credit facility and cash on hand. The Green River Processing Acquisition is accounted for as an equity investment in an unconsolidated affiliate. The investment was recorded at the historical carrying value of $107 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 portion recorded to equity was allocated among the equity owned by QEPFSC based upon the respective unit balances as of June 30, 2014, and no portion was allocated to the public ownership in QEP Midstream. The Partnership’s equity in the earnings of Green River Processing was $6 million and $10 million, for the three and six months ended June 30, 2015, respectively.

Summarized income statement information is presented below for Green River Processing.



	Three Months Ended June 30, 2015		Six Months Ended June 30, 2015
	(In millions)
Revenues	$	30	$	56
Operating Expenses	16		32
Net Income	$	14	$	24

NOTE 3 - RELATED PARTY TRANSACTIONS

As a result of the Acquisition on December 2, 2014, our General Partner became owned by QEPFS, which is a subsidiary of TLLP, and as a result, the Partnership became a consolidated subsidiary of TLLP. TLLP was formed in December 2010 by its parent, Tesoro Corporation (“Tesoro”) and TLGP. Prior to the Acquisition, QEP Midstream was a consolidated subsidiary of QEP Resources.

As of June 30, 2015, QEPFS owns 3,701,750 common units and 26,705,000 subordinated units representing an approximate 56% limited partner interest in us. In addition, our General Partner owns 1,090,495 general partner units representing a 2% general partner interest in us, as well as incentive distribution rights. Transactions with our General Partner, QEPFS and TLLP are considered to be related party transactions because our General Partner and its affiliates own more than 5% of our equity interests.

The following table summarizes the related party income statement transactions of the Partnership:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In millions)
Related party transactions with QEP Resources:
Revenues from affiliate	$	—		$	21		$	—		$	43
General and administrative expense to affiliate	—			(3		)	—			(7		)
Related party transactions with Tesoro and subsidiaries:
Revenues from affiliate	$	1		$	—		$	3		$	—
General and administrative expense to affiliate	(3		)	—			(7		)	—
Interest expense to affiliate	(1		)	—			(2		)	—

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Prior to the Acquisition, as discussed in Note 1, the Partnership was party to the Original Omnibus Agreement and various service agreements with QEP Resources and QEPFSC that resulted in affiliate transactions. Following the Acquisition, the Partnership entered into a $500 million unsecured, affiliate credit agreement with QEPFS (the “Affiliate Credit Agreement”) and the Amended Omnibus Agreement. On August 3, 2015, we terminated the Affiliate Credit Agreement and the Amended Omnibus Agreement subsequent to the completion of the Merger.

Service Agreements

Prior to the Acquisition, the Partnership entered into various midstream agreements with QEP Resources and QEPFSC including natural gas, crude oil, water and condensate gathering and transportation agreements, a fixed price condensate purchase agreement, operating agreements and other service agreements. These agreements with QEPFSC and QEP Resources were assigned to QEPFS, TLLP and TLLP’s general partner in connection with the Acquisition. The terms of the assigned agreements remained substantially similar subsequent to the Acquisition.

NOTE 4 - PROPERTY, PLANT AND EQUIPMENT

A summary of the Partnership’s property, plant and equipment is as follows:



	June 30, 2015			December 31, 2014
	(In millions)
Property, plant and equipment	$	747		$	752
Accumulated depreciation	(288		)	(276		)
Property, plant and equipment, net	$	459		$	476

Impairment

We evaluate whether long-lived assets have been impaired and determine if the carrying amount of our assets may not be recoverable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. During the three months ended June 30, 2015, the Partnership approved plans to abandon certain condensate pipelines located in western Wyoming that were no longer in use. As a result, we recorded an impairment charge of $5 million to write off the remaining book value of these assets. There were no asset impairments recognized during the three and six months ended June 30, 2014.

NOTE 5 - DEBT

On December 2, 2014, in connection with the Acquisition, we entered into the unsecured Affiliate Credit Agreement, in which QEPFS agreed to provide revolving loans and advances to us up to a borrowing capacity of $500 million. In conjunction with the closing of the Acquisition, we borrowed $230 million under the Affiliate Credit Agreement and used the funds for the repayment and termination of the Partnership’s existing $500 million revolving credit facility. At June 30, 2015 and December 31, 2014, there were $203 million and $210 million of borrowings outstanding, respectively, under the Affiliate Credit Agreement and the Partnership was in compliance with the covenants under the Affiliate Credit Agreement. At June 30, 2015, the weighted average interest rate for borrowings under our Affiliate Credit Agreement was 2.20%. On August 3, 2015, after completion of the Merger, the Affiliate Credit Agreement was terminated by converting the outstanding borrowings of $203 million into an additional QEPFS limited partner interest in us.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

TLLP Indemnification

Under the Amended Omnibus Agreement, TLLP indemnifies the Partnership for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the Acquisition. TLLP retains responsibility for remediation of known liabilities due to our operations and has indemnified the Partnership for any losses incurred by the Partnership arising out of those remediation obligations. See Note 4 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of the Amended Omnibus Agreement.

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

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. We record an accrual 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 at this time for the reasons set forth above. We believe, however, that the resolution of pending proceedings will not have a material effect on our financial position, results of operations or cash flows.

Litigation

Questar Gas Company v. QEP Field Services Company. QEPFSC’s former affiliate, Questar Gas Company (“QGC”) and its affiliate Wexpro, filed a complaint on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the “1993 Agreement”) executed when the parties were affiliates. TLLP has agreed to indemnify QEPFSC for this claim under the acquisition agreement for QEPFSC. Under the 1993 Agreement, certain of QEPFSC’s systems provide gathering services to QGC charging an annual gathering rate, which is based on the cost of service calculation. The 1993 Agreement was assigned to QEPFS on December 2, 2014, in connection with the Acquisition. QGC is disputing the annual calculation of the gathering rate, which has been calculated in the same manner since 1998, without objection by QGC. At the closing of the IPO, the assets and agreement discussed above was assigned to QEP Midstream. QGC amended its complaint to add QEP Midstream as a defendant in the litigation. Prior to the Acquisition, QEP Midstream was indemnified by QEPFSC and, effective December 2, 2014, by TLLP for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Original Omnibus Agreement and the Amended Omnibus Agreement, respectively. QGC has netted the disputed amounts from its monthly payments of the gathering fees to QEPFSC and has continued to net such amounts from its monthly payment to QEP Midstream. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits. As any losses arising from this dispute have been indemnified, we believe the outcome of this matter will not have a material impact on our liquidity, financial position, or results of operations.

NOTE 7 - EQUITY

The summarized changes in the carrying amount of our equity are as follows (in millions):



	Limited Partners
	Common Units			Subordinated Units			General Partner Units			Noncontrolling Interest			Total Net Equity
Balance at December 31, 2014	$	393		$	(36	)	$	(1	)	$	43		$	399
Distributions to noncontrolling interest	—			—			—			(4		)	(4		)
Distributions to unitholders	(17		)	(16		)	(1		)	—			(34		)
Net income	16			16			1			2			35
Balance at June 30, 2015	$	392		$	(36	)	$	(1	)	$	41		$	396

NOTE 8 - 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, 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.

Diluted net income per unit includes the effects of potentially dilutive units on our common units, which consist of unvested phantom units. Basic and diluted net income per unit applicable to subordinated limited partners was historically the same, as there were no potentially dilutive subordinated units outstanding.

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

The following tables set forth distributions in excess of net income attributable to QEP Midstream and the calculation of net income per unit for the three and six months ended June 30, 2015 and 2014 (in millions, except unit and per unit amounts).



	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015			2014
Net income attributable to QEP Midstream	$	12	$	9		$	33		$	21
General partner’s distribution declared (including IDRs) (a)	—		—			(1		)	(1		)
Limited partners’ distribution declared on common units (a)	—		(8		)	(9		)	(15		)
Limited partners’ distribution declared on subordinated units (a)	—		(8		)	(8		)	(15		)
Distribution less (greater) than net income attributable to QEP Midstream	$	12	$	(7	)	$	15		$	(10	)

____________


(a)	On April 22, 2015, the Partnership declared a quarterly cash distribution totaling $18 million, or $0.32 per unit for the first quarter of 2015. The quarterly distribution was paid on May 15, 2015. No quarterly cash distributions were declared by the Partnership for the second quarter of 2015.



	Three Months Ended June 30, 2015
	General Partner			Limited Partners’ Common Units			Limited Partners’ Subordinated Units			Total
Net income attributable to QEP Midstream:
Distribution declared (including IDRs)	$	—		$	—		$	—		$	—
Distributions less than net income attributable to QEP Midstream	—			6			6			12
Net income attributable to QEP Midstream	$	—		$	6		$	6		$	12

Weighted-average units outstanding:
Basic	1,090,495			26,749,311			26,705,000			54,544,806
Diluted	1,090,495			26,753,276			26,705,000			54,548,771
Net income per limited partner unit attributable to QEP Midstream:
Basic and diluted				$	0.24		$	0.24

	Three Months Ended June 30, 2014
	General Partner			Limited Partners’ Common Units			Limited Partners’ Subordinated Units			Total
Net income attributable to QEP Midstream:
Distribution declared (including IDRs)	$	—		$	8		$	8		$	16
Distributions greater than net income attributable to QEP Midstream	(1		)	(3		)	(3		)	(7		)
Net income attributable to QEP Midstream	$	(1	)	$	5		$	5		$	9

Weighted-average units outstanding:
Basic	1,090,286			26,719,037			26,705,000			54,514,323
Diluted	1,090,286			26,719,037			26,705,000			54,514,323
Net income per limited partner unit attributable to QEP Midstream:
Basic and diluted				$	0.18		$	0.18

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)



	Six Months Ended June 30, 2015
	General Partner			Limited Partners’ Common Units			Limited Partners’ Subordinated Units			Total
Net income attributable to QEP Midstream:
Distribution declared (including IDRs)	$	1		$	9		$	8		$	18
Distributions less than net income attributable to QEP Midstream	1			7			7			15
Net income attributable to QEP Midstream	$	2		$	16		$	15		$	33

Weighted-average units outstanding:
Basic	1,090,495			26,741,902			26,705,000			54,537,397
Diluted	1,090,495			26,745,017			26,705,000			54,540,512
Net income per limited partner unit attributable to QEP Midstream:
Basic and diluted				$	0.61		$	0.61

	Six Months Ended June 30, 2014
	General Partner			Limited Partners’ Common Units			Limited Partners’ Subordinated Units			Total
Net income attributable to QEP Midstream:
Distribution declared (including IDRs)	$	1		$	15		$	15		$	31
Distributions greater than net income attributable to QEP Midstream	(1		)	(5		)	(4		)	(10		)
Net income attributable to QEP Midstream	$	—		$	10		$	11		$	21

Weighted-average units outstanding:
Basic	1,090,230			26,716,267			26,705,000			54,511,497
Diluted	1,090,230			26,720,412			26,705,000			54,515,642
Net income per limited partner unit attributable to QEP Midstream:
Basic and diluted				$	0.39		$	0.39

NOTE 9 - CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Separate condensed consolidating financial information of QEP Midstream Partners, LP (the “Parent”), subsidiary guarantors and non-guarantors are presented below. In January 2015, the Partnership and its consolidated subsidiaries, with the exception of Rendezvous Gas, were elected guarantors of TLLP’s registered 2020 Senior Notes and 2021 Senior Notes. At June 30, 2015, the outstanding principal on these debt obligations was $470 million and $550 million for the 2020 Senior Notes and 2021 Senior Notes, respectively. As a result of these arrangements, we are required to present the following condensed consolidating financial information, which should be read in conjunction with the accompanying condensed consolidated financial statements and notes thereto. This information is provided as an alternative to providing separate financial statements for TLLP guarantor subsidiaries. Separate financial statements of the Partnership’s consolidated subsidiary guarantors are not included because the guarantees are full and unconditional and these consolidated subsidiary guarantors are 100% owned and are jointly and severally liable for TLLP’s outstanding senior notes.

Set forth below are the consolidating balance sheets for the Partnership and its subsidiaries as of June 30, 2015 and December 31, 2014, and the related consolidating statements of operations and consolidating statements of cash flows for the three and six month periods ending June 30, 2015 and 2014. The information is presented using the equity method of accounting for investments in subsidiaries. Intercompany transactions between subsidiaries are presented gross and eliminated in the eliminations column.

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries		Non-Guarantors			Eliminations			Consolidated
Revenues
Gathering and transportation	$	—		$	31	$	2		$	—		$	33
Condensate sales	—			1		7			(7		)	1
Total Revenues	—			32		9			(7		)	34
Operating Expenses
Gathering expenses	—			14		1			(7		)	8
General and administrative expenses	5			1		—			—			6
Depreciation and amortization expenses	—			5		3			—			8
Loss on asset impairments	—			5		—			—			5
Total Operating Expenses	5			25		4			(7		)	27
Operating Income (Loss)	(5		)	7		5			—			7
Income from unconsolidated affiliates	—			7		—			—			7
Equity in earnings of subsidiaries	18			4		—			(22		)	—
Interest expense	(1		)	—		—			—			(1		)
Net Income	12			18		5			(22		)	13
Net income attributable to noncontrolling interest	—			—		(1		)	—			(1		)
Net Income Attributable to QEP Midstream	$	12		$	18	$	4		$	(22	)	$	12

Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2014

(In millions)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Revenues
Gathering and transportation	$	—		$	27		$	7		$	(6	)	$	28
Condensate sales	—			2			—			—			2
Total Revenues	—			29			7			(6		)	30
Operating Expenses
Gathering expenses	—			13			—			(6		)	7
General and administrative expenses	6			(1		)	—			—			5
Depreciation and amortization expenses	—			5			3			—			8
Total Operating Expenses	6			17			3			(6		)	20
Operating Income (Loss)	(6		)	12			4			—			10
Equity in earnings of subsidiaries	15			3			—			(18		)	—
Net Income	9			15			4			(18		)	10
Net income attributable to noncontrolling interest	—			—			(1		)	—			(1		)
Net Income Attributable to QEP Midstream	$	9		$	15		$	3		$	(18	)	$	9

F-12

Table of Contents

QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries		Non-Guarantors			Eliminations			Consolidated
Revenues
Gathering and transportation	$	—		$	63	$	3		$	—		$	66
Condensate sales	—			3		13			(13		)	3
Total Revenues	—			66		16			(13		)	69
Operating Expenses
Gathering expenses	—			26		1			(13		)	14
General and administrative expenses	9			1		—			—			10
Depreciation and amortization expenses	—			10		6			—			16
Loss on asset impairments	—			5		—			—			5
Total Operating Expenses	9			42		7			(13		)	45
Operating Income (Loss)	(9		)	24		9			—			24
Income from unconsolidated affiliates	—			13		—			—			13
Equity in earnings of subsidiaries	44			7		—			(51		)	—
Interest expense	(2		)	—		—			—			(2		)
Net Income	33			44		9			(51		)	35
Net income attributable to noncontrolling interest	—			—		(2		)	—			(2		)
Net Income Attributable to QEP Midstream	$	33		$	44	$	7		$	(51	)	$	33

Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2014

(In millions)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Revenues
Gathering and transportation	$	—		$	55		$	14		$	(12	)	$	57
Condensate sales	—			4			—			—			4
Total Revenues	—			59			14			(12		)	61
Operating Expenses
Gathering expenses	—			25			—			(12		)	13
General and administrative expenses	10			—			—			—			10
Depreciation and amortization expenses	—			10			6			—			16
Total Operating Expenses	10			35			6			(12		)	39
Operating Income (Loss)	(10		)	24			8			—			22
Income from unconsolidated affiliates	—			2			—			—			2
Equity in earnings of subsidiaries	31			6			—			(37		)	—
Interest expense	—			(1		)	—			—			(1		)
Net Income	21			31			8			(37		)	23
Net income attributable to noncontrolling interest	—			—			(2		)	—			(2		)
Net Income Attributable to QEP Midstream	$	21		$	31		$	6		$	(37	)	$	21

F-13

Table of Contents

QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet as of June 30, 2015

(In millions)



	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current Assets:
Cash and cash equivalents	$	3	$	—	$	3	$	—		$	6
Accounts receivable, net	—		21		1		—			22
Accounts receivable from affiliate	—		16		2		(2		)	16
Total Current Assets	3		37		6		(2		)	44
Property, Plant and Equipment, Net	—		276		183		—			459
Long-term Receivables from Affiliates	157		—		—		(157		)	—
Investment in Unconsolidated Affiliates	—		138		—		—			138
Investment in Subsidiaries	399		145		—		(544		)	—
Total Assets	$	559	$	596	$	189	$	(703	)	$	641

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	—	$	5	$	—	$	—		$	5
Accounts payable to affiliate	—		11		—		(2		)	9
Other current liabilities	1		3		—		—			4
Total Current Liabilities	1		19		—		(2		)	18
Affiliate Long-Term Debt	203		—		—		—			203
Long-Term Payables to Affiliates	—		155		2		(157		)	—
Other Long-Term Liabilities	—		23		1		—			24
Total Long-Term Liabilities	203		178		3		(157		)	227
Equity
Equity - QEP Midstream	355		399		145		(544		)	355
Equity - noncontrolling interest	—		—		41		—			41
Total Equity	355		399		186		(544		)	396
Total Liabilities and Equity	$	559	$	596	$	189	$	(703	)	$	641

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet as of December 31, 2014

(In millions)



	Parent		Guarantor Subsidiaries		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	13	$	2	$	—		$	15
Accounts receivable, net	—		18		2		—			20
Accounts receivable from affiliate	—		2		—		—			2
Total Current Assets	—		33		4		—			37
Property, Plant and Equipment, Net	—		288		188		—			476
Long-term Receivables from Affiliates	210		—		4		(214		)	—
Investment in Unconsolidated Affiliates	—		136		—		—			136
Investment in Subsidiaries	358		152		—		(510		)	—
Total Assets	$	568	$	609	$	196	$	(724	)	$	649

LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	—	$	12	$	—	$	—		$	12
Accounts payable to affiliate	1		—		—		—			1
Other current liabilities	1		1		—		—			2
Total Current Liabilities	2		13		—		—			15
Affiliate Long-Term Debt	210		—		—		—			210
Long-Term Payables to Affiliates	—		214		—		(214		)	—
Other Long-Term Liabilities	—		24		1		—			25
Total Long-Term Liabilities	210		238		1		(214		)	235
Equity
Equity - QEP Midstream	356		358		152		(510		)	356
Equity - noncontrolling interest	—		—		43		—			43
Total Equity	356		358		195		(510		)	399
Total Liabilities and Equity	$	568	$	609	$	196	$	(724	)	$	649

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2015

(In millions)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash Flows From (Used In) Operating Activities:
Net cash from operating activities	$	(9	)	$	53		$	13		$	(14	)	$	43
Cash Flows From (Used In) Investing Activities:
Capital expenditures	—			(4		)	—			—			(4		)
Contributions to unconsolidated affiliates	—			(3		)	—			—			(3		)
Net cash used in investing activities	—			(7		)	—			—			(7		)
Cash Flows From (Used In) Financing Activities:
Borrowings under affiliate credit agreement	29			—			—			—			29
Repayments under affiliate credit agreement	(36		)	—			—			—			(36		)
Intercompany borrowings (payments)	53			(59		)	6			—			—
Distributions to unitholders	(34		)	—			—			—			(34		)
Distributions to subsidiaries	—			—			(14		)	14			—
Distribution to noncontrolling interest	—			—			(4		)	—			(4		)
Net cash from (used in) financing activities	12			(59		)	(12		)	14			(45		)
Increase (Decrease) In Cash and Cash Equivalents	3			(13		)	1			—			(9		)
Cash and Cash Equivalents, Beginning of Period	—			13			2			—			15
Cash and Cash Equivalents, End of Period	$	3		$	—		$	3		$	—		$	6

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QEP MIDSTREAM PARTNERS, LP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Cash Flows

For the Six Months Ended June 30, 2014

(In millions)



	Parent			Guarantor Subsidiaries			Non-Guarantors			Eliminations			Consolidated
Cash Flows From (Used In) Operating Activities:
Net cash from operating activities	$	28		$	33		$	14		$	(35	)	$	40
Cash Flows Used In Investing Activities:
Capital expenditures	—			(11		)	—			—			(11		)
Net cash used in investing activities	—			(11		)	—			—			(11		)
Cash Flows From (Used In) Financing Activities:
Contributions from (distributions to) parent, net	1			(24		)	(11		)	35			1
Distributions to unitholders	(29		)	—			—			—			(29		)
Distribution to noncontrolling interest	—			—			(3		)	—			(3		)
Net cash used in financing activities	(28		)	(24		)	(14		)	35			(31		)
Decrease In Cash and Cash Equivalents	—			(2		)	—			—			(2		)
Cash and Cash Equivalents, Beginning of Period	—			16			3			—			19
Cash and Cash Equivalents, End of Period	$	—		$	14		$	3		$	—		$	17

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QEP Midstream Partners, LP Management’s Discussion and Analysis

Overview

QEP Midstream (“the Partnership”) is a master limited partnership formed 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. Additionally, we have a 40% interest in two gas processing complexes through the Green River Processing Acquisition. Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the Williston Basin located in North Dakota.

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing, LLC (“Green River Processing”) from QEP Field Services Company (“QEPFSC”) for $230 million (the “Green River Processing Acquisition”). The Green River Processing Acquisition was funded with $220 million of borrowings under the Partnership’s $500 million revolving credit facility (the “Prior Credit Facility”) and cash on hand.

On December 2, 2014, QEP Resources’ midstream business was acquired by TLLP, which included all of the issued and outstanding membership interest of QEP Field Services, LLC (“QEPFS”), a wholly-owned subsidiary of QEPFSC formed for purposes of consummating the QEPFS acquisition. QEPFS is the owner of QEP Midstream Partners GP, LLC (our “General Partner”), which owns a 2% general partner interest in QEP Midstream and all of the Partnership’s incentive distribution rights. The acquisition also included an approximate 56% limited partner interest in the Partnership (collectively, the “Acquisition”). Prior to the Acquisition, QEPFSC owned and operated QEP Midstream’s general partner. This resulted in a change of control of the Partnership’s general partner and the Partnership became a consolidated subsidiary of TLLP on the acquisition date. Prior to this transaction, QEP Resources, through its wholly-owned subsidiary QEPFSC, served as the Partnership’s general partner and owned a 2% general partner interest, all of the Partnership’s incentive distribution rights and an approximate 56% limited partner interest in the Partnership.

Recent Developments

Our Operations

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

We generally do not take title to the natural gas and crude oil that we gather or transport. We provide substantially all of our gathering services pursuant to fee-based agreements, the majority of which have annual inflation adjustment mechanisms. Under these arrangements, we are paid a fixed or margin-based fee with respect to the volume of the natural gas and crude oil we gather. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. Approximately 4% of our Partnership’s revenue was generated through the sale of condensate volumes that we collected on our gathering systems during the six months ended June 30, 2015. Although the Partnership has entered into a fixed price condensate sales agreement with QEPFS, we still have indirect exposure to commodity price risk in that persistently 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 the “Commodity Price Risk” discussion in Quantitative and Qualitative Disclosures about Market Risk in Item 3 for a discussion of our exposure to commodity price risk through our condensate recovery and sales.

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Our earnings from our investment in Green River Processing are primarily driven by the volumes of natural gas processed under fee-based agreements. Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into the Keep-Whole Commodity Fee Agreement (the “Keep-Whole Commodity Agreement”) with Tesoro Refining & Marketing Company LLC (“TRMC”), a wholly-owned subsidiary of Tesoro Corporation (“Tesoro”), to minimize and mitigate commodity price risk. See Note 4 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding related party agreements.

We have significant acreage dedications from several of our largest customers. Pursuant to the terms of those agreements, our customers have dedicated all of the oil and natural gas production they own or control from (i) wells that are currently connected to our gathering systems and located within the acreage dedication and (ii) future wells that are drilled during the term of the applicable gathering contract and located within the dedicated acreage as our gathering systems currently exist and as they are expanded to connect to additional wells.

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

How We Evaluate Our Business

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.

Gathering Expenses

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

Maintenance and Growth Capital Expenditures

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

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.

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Oil and Natural Gas Supply and Demand

Our gathering operations are primarily dependent upon natural gas and crude oil production in our areas of operation. The decline in natural gas prices over the prior years has caused a related decrease in natural gas drilling in the United States. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. We anticipate the current level of exploration and production activities in all of the areas in which we operate to fluctuate, although we have no control over this activity. Fluctuations in natural gas and crude oil prices could affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas and crude oil reserves.

Commodity Price Risk

Future exposure to changes in natural gas and NGL prices could have a material adverse effect on our business, results of operations and financial condition as changes in prices will impact production levels and gathering volumes. On December 2, 2014, following the completion of the Acquisition, Green River Processing entered into the Keep-Whole Commodity Agreement with TRMC, to minimize and mitigate commodity price risk; however, it is renewed annually which is subject to renegotiation of terms and pricing each year. For the NGLs that we handle under keep-whole agreements, the Partnership has a fee-based processing agreement with Tesoro which minimizes the impact of commodity price movement during the annual period subsequent to renegotiation of terms and pricing each year. See Note 4 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding related party agreements.

Factors Affecting the Comparability of Our Financial Results

Investment in Green River Processing

On July 1, 2014, the Partnership acquired 40% of the membership interests in Green River Processing from QEPFSC for $230 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. For the three and six months ended June 30, 2015, Green River Processing net income attributable to the Partnership was $6 million and $10 million, respectively.

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Results of Operations

The discussion of our historical performance and financial condition is presented for the three and six months ended June 30, 2015 and 2014 (in millions, except in MBbls, per MMBtu, and per barrel amounts).



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Revenues
Gathering and transportation	$	33		$	28		$	66		$	57
Condensate sales	1			2			3			4
Total revenues	34			30			69			61
Operating expenses
Gathering expenses	8			7			14			13
General and administrative expenses	6			5			10			10
Depreciation and amortization expenses	8			8			16			16
Loss on asset impairments	5			—			5			—
Total operating expenses	27			20			45			39
Operating income	7			10			24			22
Income from unconsolidated affiliates (a)	7			—			13			2
Interest expense	(1		)	—			(2		)	(1		)
Net income	13			10			35			23
Net income attributable to noncontrolling interest	(1		)	(1		)	(2		)	(2		)
Net income attributable to QEP Midstream	$	12		$	9		$	33		$	21
Operating Statistics
Natural gas throughput in millions of MMBtu (b)
Gathering and transportation	78			76			151			146
Equity interest (c)	7			5			14			10
Total natural gas throughput	85			81			165			156
Throughput attributable to noncontrolling interests (d)	(3		)	(2		)	(6		)	(5		)
Total throughput attributable to QEP Midstream	82			79			159			151
Crude oil and condensate gathering system throughput volumes (in MBbls) (b)	1,323			1,112			2,588			2,182
Water gathering volumes (in MBbls) (b)	1,594			1,174			2,788			2,250
Condensate sales volumes (in MBbls) (b)	14			21			39			46
Price
Average gas gathering and transportation fee (per MMBtu)	$	0.36		$	0.31		$	0.35		$	0.31
Average oil and condensate gathering fee (per barrel)	$	2.19		$	2.39		$	2.15		$	2.37
Average water gathering fee (per barrel)	$	1.89		$	1.87		$	1.88		$	1.86
Average condensate sale price (per barrel)	$	85.25		$	85.25		$	85.25		$	85.25

_____________


(a)	Effective July 1, 2014, includes our 40% share of income from Green River Processing.

(b) We measure natural gas volumes in million British thermal units (“MMBtu”). We measure crude oil, condensate and water volumes in thousands of barrels (“MBbls”).


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


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

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Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Revenue

Gathering and transportation. Gathering and transportation revenues increased $5 million, or 18%, to $33 million for the three months ended June 30, 2015 (the “2015 Quarter”), compared to $28 million for the three months ended June 30, 2014 (the “2014 Quarter”).

Natural gas gathering and transportation revenues increased $3 million, or 13%, to $26 million for the 2015 Quarter, compared to $23 million for the 2014 Quarter. The rise in revenue in the 2015 Quarter compared to the 2014 Quarter was a result of the increase in throughput of 3 MMBtu, and an increase in average gas gathering and transportation fee of $0.05 per MMBtu, or 16%.

Revenues from crude oil, condensate and water gathering increased $2 million, or 40%, to $7 million during the 2015 Quarter, compared to $5 million for the 2014 Quarter. The average gathering fee for crude oil and condensate gathering decreased by $0.20 per barrel during the 2015 Quarter, as compared to the 2014 Quarter. This decrease was offset by a higher throughput for crude oil, condensate and water gathering during the 2015 Quarter. The 2014 Quarter also included $1 million of revenue attributable to the Williston Gathering System.

Condensate sales. Revenue from condensate sales decreased $1 million, or 50%, to $1 million during the 2015 Quarter, compared to $2 million for the 2014 Quarter. During the 2015 Quarter, sales volumes were approximately 14 MBbls at a fixed price of $85.25 per barrel pursuant to our fixed price sales agreement with QEPFS compared to 21 MBbls in the 2014 Quarter.

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased to $7 million for the 2015 Period, compared to the 2014 Period which had no income from unconsolidated affiliates. The 2015 Quarter includes $6 million of income from our 40% interest in Green River Processing, acquired July 1, 2014, and $1 million of income from our 50% interest in Three Rivers Gathering.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Revenue

Gathering and transportation. Gathering and transportation revenue increased $9 million, or 16%, to $66 million for the six months ended June 30, 2015 (the “2015 Period”), compared to $57 million for the six months ended June 30, 2014 (the “2014 Period”).

Natural gas gathering and transportation revenue increased $9 million, or 20%, to $54 million for the 2015 Period, compared to $45 million for the 2014 Period. The rise in revenue in the 2015 Period compared to the 2014 Period was a result of the increase in throughput of 8 MMBtu, and an increase in average gas gathering and transportation fee of $0.04 per MMBtu, or 13%.

Revenues from crude oil, condensate and water gathering remained consistent at $12 million during the 2015 Period and the 2014 Period. The average gathering fee for crude oil and condensate gathering decreased by $0.22 per barrel during the 2015 Period, as compared to the 2014 Period. This decrease was offset by a higher throughput for both crude oil and condensate and water gathering during the 2015 Period. The 2014 Period also included $3 million of revenue attributable to the Williston Gathering System.

Condensate sales. Revenue from condensate sales decreased $1 million, or 25%, to $3 million during the 2015 Period, compared to $4 million for the 2014 Period. During the 2015 Period, sales volumes were approximately 39 MBbls at a fixed price of $85.25 per barrel pursuant to our fixed price sales agreement with QEPFS.

Income from unconsolidated affiliates. Income from unconsolidated affiliates increased $11 million to $13 million for the 2015 Period, compared to $2 million for the 2014 Period. The 2015 Period includes $10 million of income from our 40% interest in Green River Processing, acquired July 1, 2014, and $3 million of income from our 50% interest in Three Rivers Gathering. During the 2014 Period, all of the income from unconsolidated affiliates was from our interest in Three Rivers Gathering.

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Liquidity and Capital Resources

Cash Flow

The following table and discussion present a summary of our net cash from operating activities, investing activities and financing activities for the periods indicated.



	Six Months Ended June 30,
	2015			2014
	(In millions)
Cash Flows From (Used In):
Operating Activities	$	43		$	40
Investing Activities	(7		)	(11		)
Financing Activities	(45		)	(31		)
Decrease in Cash and Cash Equivalents	$	(9	)	$	(2	)

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



	Six Months Ended June 30,
	2015			2014
	(In millions)
Net income	$	35		$	23
Non-cash adjustments to net income	21			19
Changes in operating assets and liabilities	(13		)	(2		)
Net cash from operating activities	$	43		$	40

Investing Activities. Capital expenditures are presented in the following table for the periods specified below.



	Six Months Ended June 30,
	2015		2014
	(In millions)
Total capital expenditures	$	3	$	8
Change in accruals and non-cash items	1		3
Total cash capital expenditures	$	4	$	11

Financing Activities. For the six months ended June 30, 2015, the Partnership’s cash used in financing activities consisted of $7 million of net repayments under the Affiliate Credit Agreement, $34 million in unitholder distributions, and $4 million in distributions to its noncontrolling interest in Rendezvous Gas Services. For the six months ended June 30, 2014, the Partnership’s cash used in financing activities consisted primarily of $29 million in unitholder distributions, and $3 million in distributions related to its noncontrolling interest in Rendezvous Gas Services.

Capital Requirements

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

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The following table is a summary of our capital expenditures for the periods specified below (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(In millions)
Growth	$	1	$	—	$	1	$	2
Maintenance	1		2		2		6
Total Capital Expenditures	$	2	$	2	$	3	$	8

Maintenance capital expenditures were mainly related to scheduled maintenance overhauls, the addition of combustors on the Vermillion Gathering System as required by the Environmental Protection Agency, Central Gathering Facility (“CGF”) modification projects and CGF loadbanks in the Pinedale Field.

Distributions

On January 23, 2015, the Partnership declared its quarterly cash distribution totaling $17 million, or $0.31 per unit, for the fourth quarter of 2014. This distribution was paid on February 13, 2015, to unitholders of record on the close of business on February 3, 2015. On April 22, 2015, the Partnership declared a quarterly cash distribution totaling $18 million, or $0.32 per unit for the first quarter of 2015. The quarterly distribution was paid on May 15, 2015, to unitholders of record as of the close of business on May 4, 2015. No quarterly cash distributions were declared by the Partnership for the second quarter of 2015 as a result of the merger with TLLP closing in July 2015.

Affiliate Credit Agreement

On December 2, 2014, we entered into the $500 million unsecured, Affiliate Credit Agreement with QEPFS. Under the Affiliate Credit Agreement, QEPFS agreed to provide revolving loans and advances to us up to a borrowing capacity of $500 million. As of June 30, 2015, there was $203 million outstanding under the Affiliate Credit Agreement. On August 3, 2015, after completion of the Merger, the Affiliate Credit Agreement was terminated by converting the outstanding borrowings of $203 million into an additional QEPFS limited partner interest in us.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

Our exposure to credit risk may be affected by our concentration of customers due to changes in economic or other conditions. Our customers include companies that may react differently to changing conditions. Our principal customers are QEP Resources and Questar Gas Company (“QGC”). We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including QEP Resources and QGC. Consequently, we are subject to the risk of non-payment or late payment by QEP Resources and QGC of gathering fees, and this risk is greater than it would be with a broader customer base with a similar credit profile.

Our gathering agreement with QGC is the subject of ongoing litigation, in which QGC is disputing the calculation of the gathering rate and has been netting the disputed amount from its monthly payment of gathering fees to QEPFSC and the Partnership since the second quarter of 2012. The Partnership has been indemnified by TLLP for costs, expenses and other losses incurred by the Partnership in connection with the QGC dispute, subject to certain limitations, as set forth in the Amended Omnibus Agreement. In December 2014, the trial court granted a partial summary judgment in favor of QGC on the issues of the appropriate methodology for certain of the cost of service calculations. As a result of our indemnification by TLLP, the outcome of this litigation is not expected to have a material impact on our financial condition, results of operations, or liquidity. Issues regarding other calculations, the amount of damages and certain counterclaims in the litigation remain open pending a trial on the merits. For more information regarding the litigation with QGC, refer to Note 6 - Commitments and Contingencies.

We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on our principal customers, and in particular QEP Resources, for our revenues. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

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QEP MIDSTREAM PARTNERS, LP

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below will not have a material impact on our liquidity, consolidated financial position, or results of operations. There were no new proceedings or material developments in proceedings that were previously reported in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 1A. RISK FACTORS

There have been no significant changes from the risk factors previously disclosed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014.

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

The table below provides a summary of all purchases by the Partnership of its common units during the three month period ended June 30, 2015.



Period	Total Number of Units Purchased (a)	Average Price Paid per Unit		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Units that May Yet Be Purchased Remaining at Period End Under the Plan or Programs (In Millions)
April 2015	—	$	—	—	$	—
May 2015	4,474	$	17.94	—	$	—
June 2015	—	$	—	—	$	—
Total	4,474			—

_____________


(a)	The entire 4,474 units were acquired from employees during the second quarter of 2015, to satisfy tax withholding obligations in connection with the settlement of phantom units issued to them.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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Terms and pricing under this agreement are revised each year. The Keep-Whole Commodity Agreement minimizes the impact of commodity price movement during the annual period subsequent to renegotiation of terms and pricing each year. However the annual fee we charge TRMC could be impacted as a result of any changes in the spread between NGL sales prices and the price of natural gas. See Note 4 of our Annual Report on Form 10-K for the year ended December 31, 2014, for additional information regarding the terms and conditions of the Keep-Whole Commodity Agreement.

ITEM 4. CONTROLS AND PROCEDURES

Our disclosure controls and procedures are designed to provide reasonable assurance that the information that we are required to disclose in reports we file under the Securities Exchange Act of 1934, as amended (“the Exchange Act”), is accumulated and appropriately communicated to management. In 2014, we completed a transition from the 1992 framework of the Committee of Sponsoring Organizations of the Treadway Commission to its 2013 framework for assessing our internal control effectiveness over financial reporting. There have been no significant changes in our internal controls over financial reporting (as defined by applicable Securities and Exchange Commission rules) during the quarter ended June 30, 2015, that have materially affected or are reasonably likely to materially affect these controls.

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Green River Processing, LLC Financial Statements

GREEN RIVER PROCESSING, LLC

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(In millions)
Revenues
Third-party revenue	$	18	$	28	$	33	$	60
Affiliate revenue	12		8		23		15
Total Revenue	30		36		56		75
Operating Expenses
Processing expense	4		11		8		21
Transportation and fractionation costs	9		11		17		20
General and administrative expenses	1		4		3		8
Depreciation and amortization expenses	2		2		4		4
Total Operating Expenses	16		28		32		53
Net Income	$	14	$	8	$	24	$	22

See notes accompanying the condensed financial statements.

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GREEN RIVER PROCESSING, LLC

CONDENSED BALANCE SHEETS

(Unaudited)



	June 30, 2015			December 31, 2014
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	6		$	6
Accounts receivable, net	9			10
Accounts receivable from affiliate	17			11
Total Current Assets	32			27
Gross property, plant and equipment	320			317
Less accumulated depreciation and amortization	(43		)	(39		)
Net Property, Plant and Equipment	277			278
Total Assets	$	309		$	305

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	6		$	10
Accounts payable to affiliate	10			10
Total Current Liabilities	16			20
Asset Retirement Obligation	5			5
Commitments and Contingencies (Note 4)
Equity
Owners’ net investment	288			280
Total Equity	288			280
Total Liabilities and Equity	$	309		$	305

See notes accompanying the condensed financial statements.

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GREEN RIVER PROCESSING, LLC

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2015			2014
	(In millions)
Cash Flows from (used in) Operating Activities:
Net income	$	24		$	22
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization expenses	4			4
Changes in current assets and liabilities	(9		)	(15		)
Changes in other assets and liabilities	1			2
Net cash from operating activities	20			13

Cash Flows used in Investing Activities:
Capital expenditures	(4		)	(3		)
Net cash used in investing activities	(4		)	(3		)

Cash Flows from (used in) Financing Activities:
Other capital contributions	8			—
Distributions to owners	(24		)	(10		)
Net cash used in financing activities	(16		)	(10		)

Increase (Decrease) in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents, Beginning of Period	6			—
Cash and Cash Equivalents, End of Period	$	6		$	—
Supplemental Cash Flow disclosure of non-cash activities:
Capital expenditures included in accounts payable at period end	$	—		$	1

See notes accompanying the condensed financial statements.

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GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION

Organization

Green River Processing consists of the assets and operations of the Blacks Fork gas processing complex and the Emigrant Trail gas plant (the “Assets”), both of which are located in southwest Wyoming. Processing capacity of the Assets include cryogenic and Joule-Thomson capacity, as well as natural gas liquids (“NGLs”) fractionation capacity at the Blacks Fork complex.

Green River Processing is a Delaware limited liability company that was organized on February 6, 2014, and was initially wholly-owned by QEP Field Services Company (“QEPFSC”), which is a wholly-owned subsidiary of QEP Resources, Inc. (“QEP Resources”). Prior to the formation of Green River Processing, the Assets were owned and operated by QEPFSC. On July 1, 2014, QEPFSC conveyed the Assets to Green River Processing (the “Contribution”) in connection with its sale of 40% of the membership interests in Green River Processing to QEP Midstream Partners Operating, LLC, which is wholly-owned by QEP Midstream Partners, LP (“QEPM”).

On December 2, 2014, TLLP acquired QEP Resources’ midstream business, QEPFS, which was previously wholly-owned by QEPFSC. QEPFS owns a 60% membership interest in Green River Processing and approximately 58% of general and limited partnership units of QEPM, which owns the remaining 40% membership interest of Green River Processing through QEP Midstream Partners Operating, LLC (collectively, the “Acquisition”). On July 22, 2015, TLLP acquired the remaining limited partner units of QEPM. Subsequent to this transaction, QEPFS and QEP Midstream Partners Operating, LLC continue to hold the 60% and 40% membership interests, respectively, in Green River Processing but are now both wholly-owned subsidiaries of TLLP.

Basis of Presentation

The financial statements were prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All significant intercompany accounts and transactions have been eliminated in consolidation. Financial results reported for the three and six months ended June 30, 2014 have been prepared from the historical accounting records owned and maintained by QEP Resources. Further, financial information for the three and six months ended June 30, 2014 was carved out from QEPFSC data, because separate and distinct accounts for the operation of the Assets were not maintained. Financial results reported for the three and six months ended June 30, 2015 have been prepared from records owned and maintained by TLLP.

The preparation of the financial statements and notes in conformity with GAAP requires that management formulate estimates and assumptions that affect the amounts of assets and liabilities and revenues and expenses reported as of and during the periods presented. The Company reviews these estimates on an ongoing basis using currently available information. Changes in facts and circumstances may result in revised estimates, and actual results could differ from those estimates.

There were no assets or liabilities accounted for at fair value on a recurring basis as of June 30, 2015. Management believes the carrying value of our current assets and liabilities approximate fair value. Green River Processing is a limited liability company that is classified as a partnership for income tax purposes.

QEPFS and certain of its subsidiaries, including Green River Processing, were elected guarantors of TLLP’s registered 2020 Senior Notes and 2021 Senior Notes in January 2015. The guarantees are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the applicable indenture.

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GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Recent Accounting Developments

Revenue Recognition. In May 2014, The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), which provides accounting guidance for all revenue arising from contracts to provide goods or services to customers. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017 given the FASB’s recent deferral of ASU 2014-09’s effective date. Entities may choose to early adopt ASU 2014-09 as of the original effective date. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the standard to determine the method of adoption and the impact of ASU 2014-09 on our financial statements and related disclosures.

Pushdown Accounting. The Securities and Exchange Commission (“SEC”) released a Staff Accounting Bulletin in November 2014, overturning portions of the interpretive guidance regarding pushdown accounting. Effective November 18, 2014, the new bulletin aligns the existing guidance to the ASU issued by the FASB in October 2014. Under the new guidance, pushdown accounting can be applied in the separate financial statements of the acquired entity upon completion of the acquisition or in a subsequent period. This impacts the stand-alone financial statements of the subsidiary, but does not alter the existing reporting requirements for the parent company to record the acquired assets, liabilities, and non-controlling interests in consolidated financial statements. If pushdown accounting is not applied in the reporting period in which the change-in-control event occurs, an acquired entity will have the option to elect to apply pushdown accounting in a subsequent reporting period. If pushdown accounting is applied, that election is irrevocable. The SEC responded by rescinding its guidance on pushdown accounting, which had required registrants to apply pushdown accounting in certain circumstances. With regard to the Acquisition, TLLP elected not to apply pushdown accounting to Green River Processing.

NOTE 2 - RELATED PARTY TRANSACTIONS

Transactions with QEP Resources and QEPFSC were considered related party for the period prior to the Acquisition, including the three and six months ended June 30, 2014. Subsequent to the Acquisition, including the three and six months ended June 30, 2015, transactions between QEPFS and TLLP are considered related party.

The following table summarizes the other affiliate revenue (expense) transactions with QEP Resources and QEPFSC (“QEP Entities”) and Tesoro, Tesoro Refining & Marketing Company LLC (“TRMC”), Tesoro Logistics GP, LLC (“TLGP”), TLLP or any of TLLP’s subsidiaries (“Tesoro Entities”):



	Tesoro Entities		QEP Resources		Tesoro Entities		QEP Resources
	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(In millions)
Revenue from affiliate	$	12	$	8	$	23	$	15
General and administrative expenses	1		4		3		8

Centralized Cash Management

Operation of the Assets were funded by QEP Resources and managed under QEP Resources’ centralized cash management program prior to the Acquisition and are currently under TLLP’s cash management program. Sales and purchases related to third-party transactions were settled in cash but were received or paid by QEP Resources within the centralized cash management system for the three and six months ended June 30, 2014, or by TLLP for the three and six months ended June 30, 2015.

Allocation of Costs

The employees supporting Green River Processing’s operations were employees of QEPFSC and QEP Resources during the six months ended June 30, 2014 or TLGP, the general partner of TLLP, during the six months ended June 30, 2015. The financial statements of Green River Processing include direct charges for operations and support of our assets and costs allocated by QEP Resources, TLLP or TLGP. These allocated costs are reimbursed and relate to various business and corporate services and compensation-related costs.

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GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Keep-Whole Commodity Fee Agreement

Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into a five-year agreement with TRMC, a wholly-owned subsidiary of Tesoro Corporation, which transfers Green River Processing’s commodity risk exposure associated with keep-whole processing agreements to TRMC (the “Keep-Whole Commodity Agreement”). Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a British thermal unit (“BTU”) content equivalent to the NGLs removed. The operating margin for these contracts is determined by the spread between NGL sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). Under the Keep-Whole Commodity Agreement with TRMC, TRMC pays Green River Processing a fee to process NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of Green River Processing. Green River Processing pays TRMC a marketing fee in exchange for assuming the commodity risk.

Annual General & Administrative Services Fee

As part of the Contribution, Green River Processing entered into the Limited Liability Company Agreement of Green River Processing, LLC (the “Operating Agreement”), which provided that Green River Processing pay QEPFSC an annual general and administrative services fee of $7 million. The rights and provisions of the Operating Agreement were transferred from QEPFSC to QEPFS in connection with the Acquisition, and there were no changes to the annual fee. Effective July 31, 2015, the Operating Agreement was amended to eliminate the general and administrative services fee payable to QEPFS due to the consolidation of ownership interests under TLLP following TLLP’s acquisition of the remaining limited partner units in QEPM. Refer to Note 1 for further discussion.

Gas Conditioning Agreement

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

NOTE 3 - EQUITY

Membership interest percentages as of June 30, 2015 are as follows: 60% QEPFS and 40% QEP Midstream Partners Operating, LLC, which is wholly-owned by QEPM.



	QEPFS			QEP Midstream Partners Operating, LLC			Total Net Equity
	(In millions)
Balance at December 31, 2014	$	168		$	112		$	280
Capital contributions	5			3			8
Distributions to owners	(14		)	(10		)	(24		)
Net income	14			10			24
Balance at June 30, 2015	$	173		$	115		$	288

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GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 4 - COMMITMENTS AND CONTINGENCIES

Contingencies

Legal

The Company does not have any material outstanding lawsuits, administrative proceedings or governmental investigations.

Green River Processing, LLC Management’s Discussion and Analysis

Overview

Green River Processing consists of the assets and operations of the Blacks Fork gas processing complex and the Emigrant Trail gas plant, both of which are located in southwest Wyoming. The combined processing capacity of the Assets is 890 million cubic feet per day, or MMcf/d, of which 560 MMcf/d is cryogenic capacity and 330 MMcf/d is Joule-Thomson processing capacity. In addition, there is 15,000 barrels per day of natural gas liquids fractionation capacity at the Blacks Fork complex.

Green River Processing is a Delaware limited liability company that was organized on February 6, 2014, and was initially wholly-owned by QEPFSC, which is a wholly-owned subsidiary of QEP Resources. Prior to the formation of Green River Processing, the Assets were owned and operated by QEPFSC. On July 1, 2014, QEPFSC conveyed the Assets to Green River Processing in connection with its sale of 40% of the membership interests in Green River Processing to QEPM.

On December 2, 2014, TLLP acquired QEP Resources’ midstream business, QEPFS, which was previously wholly-owned by QEPFSC. As of June 30, 2015, QEPFS owns a 60% membership interest in Green River Processing and approximately 58% of general and limited partnership units of QEPM which owns the remaining 40% membership interest of Green River Processing.

Operations

Green River Processing provides natural gas processing services to separate NGL from the natural gas, fractionating the resulting NGL into the various components and selling or delivering pipeline quality natural gas and NGL to various industrial and energy markets as well as interstate pipeline systems. These services are provided under fee-based and keep-whole contracts.

Under fee-based arrangements, the Company receives a fee or fees for gas processing and NGL marketing services. The revenue earned from fee-based arrangements is tied directly to the volume of gas processed by the facilities or the volume of NGL sold and is not directly dependent on commodity prices.

Under keep-whole arrangements, Green River Processing processes the natural gas for a customer and retains the resulting NGL. The extraction of NGL from natural gas during processing reduces the British thermal unit (“Btu”) content of the gas. As a result, Green River Processing must either purchase gas at market prices to return to producers or make a cash payment to the producers equal to the value of the Btu content removed by processing the gas. These keep-whole agreements expose us to the spread between NGL product prices and the purchase price of natural gas. Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate the commodity price risk under these arrangements. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.

How We Evaluate Our Business

Our management uses several financial and operating metrics to analyze our performance, including throughput volumes, processing margin and operating expenses, and general and administrative expenses.

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Throughput Volumes

The amount of processing revenue we generate primarily depends on the volumes of natural gas we process for our customers. The volumes processed at our facilities are primarily affected by upstream development drilling and production volumes from the wells connected to our gathering and processing assets. We generally expect the level of drilling to correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to correlate with drilling activity.

Processing Margin and Operating Expenses

Our processing margin consists of both fee-based and keep-whole arrangements. The amount of fee-based revenue we generate is dependent upon the volumes of natural gas that are processed under these contracts through our facilities. Additionally, during 2015 our keep-whole processing margin was the difference between our NGL product sales price, the purchase price of natural gas and transportation and fractionation costs. Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate the commodity price risk under its keep-whole processing arrangements. As a result of the Keep-Whole Commodity Agreement, revenues earned during 2014 through NGL sales are now earned under NGL processing agreements. As such, there were no NGL sales during the three and six months ended June 30, 2015. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.

We seek to maximize our processing margin by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our facilities. Direct labor costs, transportation and fractionation 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.

General and Administrative Expenses

Our general and administrative expenses included both direct costs and costs allocated by QEPFSC and QEP Resources for the three and six months ended June 30, 2014, or TLGP and TLLP for the three and six months ended June 30, 2015. Direct general and administrative costs include expenses such as professional services and labor and benefits, including bonuses and share-based compensation. These allocated costs relate to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) restructuring, compensation, share-based compensation, and other post-retirement costs. The general and administrative costs incurred during 2015 primarily relate to service fees due to QEPFS under the Limited Liability Company Agreement of Green River Processing, LLC (the “Operating Agreement”). See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.

General Trends and Outlook

Operating Costs and Inflation

Until recently, we have faced increased competition for personnel and equipment due to the significant increase in exploration, development and production activities across the United States. This has typically resulted in an increase 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. However, due to recent decreases in commodity prices, exploration, development and production activities across the United States are slowing which may reverse these trends and result in lower costs for our operations. Generally, we attempt to recover our operating costs, increased or otherwise, 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.

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Factors Affecting the Comparability of Our Financial Results

Financial results reported for the three and six months ended June 30, 2014 reflect results of operations under the management of QEP Resources, and have been prepared from the historical accounting records owned and maintained by QEP Resources. Further, financial information for the three and six months ended June 30, 2014 was carved out from QEPFSC data, because separate and distinct accounts for the operation of the Assets were not maintained. Financial data reported for the three and six months ended June 30, 2015 reflect results of operations under the management of TLLP and have been prepared from records owned and maintained by TLLP.

Effective December 2, 2014, following the completion of the Acquisition, Green River Processing entered into a five-year agreement with TRMC, a wholly-owned subsidiary of Tesoro Corporation, which transfers Green River Processing’s commodity risk exposure associated with the Keep-Whole Commodity Agreement. Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a BTU content equivalent to the NGLs removed. The operating margin for these contracts is determined by the spread between NGL sales prices and the price paid to purchase the Shrink Gas. Under the Keep-Whole Commodity Agreement with TRMC, TRMC pays Green River Processing a fee to process NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of Green River Processing. Green River Processing pays TRMC a marketing fee in exchange for assuming the commodity risk. In the three and six months ended June 30, 2015, as a result of the Keep-Whole Commodity Agreement, revenue earned during 2014 through NGL sales is now earned under NGL processing agreements.

Results of Operations

The following table and discussion is an explanation of our results of operations for the three and six months ended June 30, 2015 and 2014 (in millions, except MMBtu/d, barrel per day, gallon, per MMBtu, per barrel and per gallon amounts).

Management uses average fee-based processing revenue per MMBtu, average NGL revenue per barrel and average NGL revenue per gallon to evaluate performance and compare profitability to other companies in the industry. There are a variety of ways to calculate average fee-based processing revenue per MMBtu, average NGL revenue per barrel and average NGL revenue per gallon; other companies may calculate these in different ways. We calculate average fee-based processing revenue per MMBtu as revenue divided by total throughput (MMBtu). We calculate average NGL revenue per barrel as revenue divided by total throughput (barrels). Prior to the execution of the Keep-Whole Commodity Agreement discussed above, we used average NGL revenue per gallon as a metric to analyze results. We calculated average NGL revenue per gallon as revenue divided by volume (gallons). Investors and analysts use these financial measures to help analyze and compare companies in the industry on the basis of operating performance. These financial measures should not be considered as an alternative to segment operating income, revenues and operating expenses or any other measure of financial performance presented in accordance with U.S. GAAP.

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	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues
NGL sales (a)	$	—	$	19	$	—	$	41
NGL processing revenue (a)	12		—		23		—
Fee-based processing revenue	10		9		19		17
Other processing revenue (b)	8		8		14		17
Total Revenues	30		36		56		75
Operating Expenses
Processing expense	4		11		8		21
Transportation and fractionation costs (b)	9		11		17		20
General and administrative expenses	1		4		3		8
Depreciation and amortization expenses	2		2		4		4
Total Operating Expenses	16		28		32		53
Net Income	$	14	$	8	$	24	$	22
Volumes
NGL sales volumes (thousands of gallons)	—		9,417		—		25,805
Average NGL sales revenue per gallon of NGLs	$	—	$	2.06	—		$	1.59
NGL processing throughput (bpd)	3,646		—		3,679		—
Average NGL processing revenue per barrel of NGL	$	36.94	$	—	$	34.76	$	—
Fee-based processing throughput (thousands of MMBtu/d)	386		344		366		324
Average fee-based processing revenue per MMBtu	$	0.28	$	0.28	$	0.28	$	0.28

____________

(a)

Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate the commodity price risk under its keep-whole processing arrangements. As a result of the Keep-Whole Commodity Agreement, revenues earned during the three and six months ended June 30, 2014 through NGL sales are now earned under NGL processing agreements. As such, there were no NGL sales during the three and six months ended June 30, 2015. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.


(b)	Other processing revenue includes pass-through revenues associated with transportation and fractionation costs that are incurred by Green River Processing and then passed on to the customer.

Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Volumes. Average fee-based processing volumes were 386 thousand MMBtu/d for the three months ended June 30, 2015 (the “2015 Quarter”), which is an increase of 12% compared to 344 thousand MMBtu/d for the three months ended June 30, 2014 (the “2014 Quarter”). The increase in average fee-based processing volumes is primarily attributable to the increased third-party activity. Average NGL processing volumes were 3,646 bpd for the 2015 Quarter. There were no NGL processing volumes in the 2014 Quarter, as the transactions in that period were NGL sales under keep-whole agreements rather than NGL processing agreements. There were no NGL sales volumes for the 2015 Quarter, compared to 9,417 thousand gallons for the 2014 Quarter, as the transactions in the current period were made under NGL processing agreements rather than NGL sales under keep-whole agreements. Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate the commodity price risk under its keep-whole processing arrangements. As a result of the Keep-Whole Commodity Agreement, revenue earned during the 2014 Quarter through NGL sales is now earned under NGL processing agreements. Revenue previously earned through NGL sales is now earned under fee-based agreements. See further discussion of financial results below. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.

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Financial Results. Total processing revenues decreased by $6 million to $30 million for the 2015 Quarter, from $36 million in the 2014 Quarter primarily due to the decrease in revenues related to NGLs. Our revenues related to the processing of NGLs in the 2015 Quarter are not comparable to our NGL sales revenues in the 2014 Quarter, which were based on third-party NGL sales not handled by us in the 2015 Quarter. Fee-based processing revenues were $10 million for the 2015 Quarter, which increased due to higher volumes compared to the $9 million reported in the 2014 Quarter. Other processing revenue is comprised of pass-through revenues associated with transportation and fractionation costs that are paid by Green River Processing and then reimbursed by the customer. In the 2015 Quarter, other processing revenues were $8 million, which is consistent with the 2014 Quarter.

Processing expenses were $4 million for the 2015 Quarter, compared to $11 million for the 2014 Quarter. There were no costs to purchase natural gas in the 2015 Quarter under the Keep-Whole Commodity agreement as compared to the 2014 Quarter, which is the primary reason for the $7 million decrease. Transportation and fractionation costs were $9 million in the 2015 Quarter, compared to $11 million for the 2014 Quarter. This decrease is due to higher fee-based NGL production in the 2014 Quarter.

General and administrative expenses decreased $3 million, compared to $4 million for the 2014 Quarter. The amount for the 2015 Quarter primarily relates to general and administrative services fees due to QEPFS under the Operating Agreement. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement. During the 2014 Quarter, general and administrative expense included direct charges for operations and support of the assets and costs allocated by QEP Resources. The decrease in costs during the 2015 Quarter as compared to the 2014 Quarter is due to differences in direct and allocated costs under QEP Resources for the 2014 Quarter and the service fee under the Operating Agreement that was in effect during the 2015 Quarter.

Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Volumes. Average fee-based processing volumes were 366 thousand MMBtu/d for the six months ended June 30, 2015 (the “2015 Period”), which is an increase of 13% compared to 324 thousand MMBtu/d for the six months ended June 30, 2014 (the “2014 Period”). The increase in average fee-based processing volumes is primarily attributable to the increased third-party activity. Average NGL processing volumes were 3,679 bpd for the 2015 Period. There were no NGL processing volumes in the 2014 Period, as the transactions in that period were NGL sales under keep-whole agreements rather than NGL processing agreements. There were no NGL sales volumes for the 2015 Period, compared to 25,805 thousand gallons for the 2014 Period, as the transactions in the current period were made under NGL processing agreements rather than NGL sales under keep-whole agreements. Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate the commodity price risk under its keep-whole processing arrangements. As a result of the Keep-Whole Commodity Agreement, revenue earned during the 2014 Period through NGL sales is now earned under NGL processing agreements. Revenue previously earned through NGL sales is now earned under fee-based agreements. See further discussion of financial results below. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement.

Financial Results. Total processing revenues decreased by $19 million to $56 million for the 2015 Period from $75 million in the 2014 Period primarily due to the decrease in revenues related to NGLs. Our revenues related to the processing of NGLs in the 2015 Period are not comparable to our NGL sales revenues in the 2014 Period, which were based on third-party NGL sales not handled by us in the 2015 Period. Fee-based processing revenues were $19 million for the 2015 Period, which increased due to higher volumes compared to the $17 million reported in the 2014 Period. Other processing revenue is comprised of pass-through revenues associated with transportation and fractionation costs that are paid by Green River Processing and then reimbursed by the customer. In the 2015 Period, other processing revenues were $14 million, compared to $17 million in the 2014 Period. The decrease is due to higher fee-based NGL production in the 2014 Period.

Processing expenses were $8 million for the 2015 Period, compared to $21 million for the 2014 Period. There were no costs to purchase natural gas in the 2015 Period under the Keep-Whole Commodity agreement as compared to the 2014 Period, which is the primary reason for the $13 million decrease. Transportation and fractionation costs were $17 million in the 2015 Period compared to $20 million for the 2014 Period. This decrease is due to higher fee-based NGL production in the 2014 Period.

General and administrative expenses decreased $5 million, compared to $8 million for the 2014 Period. The amount for the 2015 Period primarily relates to general and administrative service fees due to QEPFS under the Operating Agreement. See Note 2 in Green River Processing’s Notes to the Condensed Financial Statements on page F-32 for more information regarding this agreement. During the 2014 Period, general and administrative expense included direct charges for operations and support of the assets and costs allocated by QEP Resources. The decrease in costs during the 2015 Period as compared to the 2014 Period is due to differences in direct and allocated costs under QEP Resources for the 2014 Period and the service fee under the Operating Agreement that was in effect during the 2015 Period.

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Liquidity and Capital Resources

Cash Flow

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



	Six Months Ended June 30,
	2015			2014
	(In millions)
Cash Flows From (Used In):
Operating Activities	$	20		$	13
Investing Activities	(4		)	(3		)
Financing Activities	(16		)	(10		)
Increase (Decrease) in Cash and Cash Equivalents	$	—		$	—

Operating Activities. Net cash from operating activities increased to $20 million for the 2015 Period, compared to $13 million for the 2014 Period, primarily due to higher net income as compared to the 2014 Period.

Financing Activities. Net cash used in financing activities for the 2015 Period was $16 million compared to $10 million for the 2014 Period. Contributions of $8 million made to the Company partially offset $24 million of distributions to our members during the 2015 Period. There were $10 million in distributions paid during the 2014 Period to QEP Resources.

Capital Requirements

Our primary cash requirements relate to funding capital expenditures, meeting operational needs and paying distributions to our members. Expected ongoing sources of liquidity include cash generated from operations and capital contributions. 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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Credit Risk

Exposure to credit risk may be affected by the concentration of customers due to changes in economic or other conditions. Customers include individuals and commercial and industrial enterprises that may react differently to changing conditions. Management believes that its credit-review procedures, loss reserves, customer deposits and collection procedures have adequately provided for usual and customary credit-related losses.

F-38

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