ANDEAVOR LOGISTICS LP - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - ANDEAVOR LOGISTICS LP	Financial_Report.xls
EX-32.1 - EXHIBIT 32.1 - ANDEAVOR LOGISTICS LP	tllpex3213312015.htm
EX-31.1 - EXHIBIT 31.1 - ANDEAVOR LOGISTICS LP	tllpex3113312015.htm
EX-32.2 - EXHIBIT 32.2 - ANDEAVOR LOGISTICS LP	tllpex3223312015.htm
EX-10.2 - EXHIBIT 10.2 - ANDEAVOR LOGISTICS LP	tllpex102directorcompensat.htm
EX-31.2 - EXHIBIT 31.2 - ANDEAVOR LOGISTICS LP	tllpex3123312015.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 March 31, 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

The registrant had 80,605,673 common units and 1,631,448 general partner units outstanding at May 4, 2015.

TESORO LOGISTICS LP

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2015

TABLE OF CONTENTS



PART I. FINANCIAL INFORMATION		Page

Item 1.	Financial Statements (Unaudited)	3

	Condensed Statements of Combined Consolidated Operations - Three Months Ended March 31, 2015 and 2014	3

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

	Condensed Statements of Combined Consolidated Cash Flows - Three Months Ended March 31, 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	24

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 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 March 31,
	2015			2014 (a)
	(Dollars in millions, except unit and per unit amounts)
REVENUES
Affiliate	$	148		$	111
Third-party	115			16
Total Revenues	263			127
COSTS AND EXPENSES
Operating and maintenance expenses	94			52
Imbalance settlement gains and reimbursements from Tesoro	(8		)	(7		)
General and administrative expenses	25			10
Depreciation and amortization expenses	44			16
Gain on asset disposals and impairments	—			(4		)
Total Costs and Expenses	155			67
OPERATING INCOME	108			60
Interest and financing costs, net	(37		)	(18		)
Equity in earnings of unconsolidated affiliates	3			—
NET INCOME	$	74		$	42

Loss attributable to Predecessors	—			1
Net income attributable to noncontrolling interest	(10		)	—
Net income attributable to partners	64			43
General partner’s interest in net income, including incentive distribution rights	(14		)	(7		)
Limited partners’ interest in net income	$	50		$	36

Net income per limited partner unit:
Common - basic and diluted	$	0.63		$	0.64
Subordinated - basic and diluted	$	—		$	0.64

Weighted average limited partner units outstanding:
Common units - basic	80,250,208			39,186,006
Common units - diluted	80,281,988			39,284,388
Subordinated units - basic and diluted	—			15,254,890

Cash distributions paid per unit	$	0.6675		$	0.5650

_____________

(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)



	March 31, 2015			December 31, 2014
	(Dollars in millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents (QEPM: $8 and $15, respectively)	$	16		$	19
Receivables, net
Trade	125			122
Affiliate	76			69
Other	16			18
Prepayments and other	4			7
Total Current Assets	237			235
NET PROPERTY, PLANT AND EQUIPMENT (QEPM: $470 and $476, respectively)	3,335			3,306
INTANGIBLES	966			973
GOODWILL	168			164
INVESTMENT IN UNCONSOLIDATED AFFILIATES	59			57
OTHER NONCURRENT ASSETS	31			30
Total Assets	$	4,796		$	4,765

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable
Trade	$	112		$	126
Affiliate	68			53
Accrued interest and financing costs	62			28
Other current liabilities	57			79
Total Current Liabilities	299			286
OTHER NONCURRENT LIABILITIES	62			45
DEBT, NET OF UNAMORTIZED ISSUANCE COSTS	2,520			2,544
COMMITMENTS AND CONTINGENCIES (NOTE 7)
EQUITY
Common unitholders; 80,605,673 units issued and outstanding (80,125,930 in 2014)	1,500			1,474
General partner; 1,631,448 units issued and outstanding (1,631,448 in 2014)	(21		)	(19		)
Noncontrolling interest	436			435
Total Equity	1,915			1,890
Total Liabilities and Equity	$	4,796		$	4,765

See accompanying notes to combined consolidated financial statements.

Table of Contents

TESORO LOGISTICS LP

CONDENSED STATEMENTS OF COMBINED CONSOLIDATED CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2015			2014 (a)
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:	(Dollars in millions)
Net income	$	74		$	42
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization expenses	44			16
Amortization of debt issuance costs	2			1
Unit-based compensation expense	1			—
Gain on asset disposals and impairments	—			(4		)
Earnings from unconsolidated affiliates in excess of distributions	(1		)	—
Changes in current assets and current liabilities:
Receivables	(8		)	(8		)
Other current assets	3			—
Current liabilities	20			22
Changes in other non-current assets and non-current liabilities	17			—
Net cash from operating activities	152			69
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures	(82		)	(25		)
Proceeds from sale of assets	—			10
Net cash used in investing activities	(82		)	(15		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from issuance of units, net of issuance costs	24			—
Quarterly distributions to unitholders	(54		)	(31		)
Quarterly distributions to general partner	(16		)	(5		)
Distributions to noncontrolling interest	(9		)	—
Borrowings under revolving credit agreement	99			—
Repayments under revolving credit agreement	(124		)	—
Financing costs	—			(1		)
Capital contributions by affiliate	7			1
Sponsor contribution of equity to the Predecessor	—			2
Net cash used in financing activities	(73		)	(34		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(3		)	20
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	19			23
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	16		$	43

SUPPLEMENTAL CASH FLOW DISCLOSURE OF NON-CASH ACTIVITIES:
Capital expenditures included in accounts payable at period end	$	46		$	13

_____________

(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

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. The words “we,” “us,” “our,” or “ours” generally include our 57.8% interest in QEP Midstream Partners, LP (“QEPM”), a publicly traded limited partnership, 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.

Subsequent Event

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”). Subject to the satisfaction or waiver of certain conditions in the Merger Agreement, upon the later of the filing with the Secretary of State of the State of Delaware of a certificate of merger or the later date and time set forth in such certificate, Merger Sub will merge with and into QEPM, with QEPM surviving the merger as a wholly owned subsidiary of TLLP (the “Merger”). Following the Merger, QEPM GP will remain the general partner of QEPM, and all outstanding common units representing limited partnership interests in QEPM (the “QEPM Common Units”) other than QEPM Common Units held by QEPFS will be converted into the right to receive 0.3088 common units representing limited partnership interests in TLLP (the “TLLP Common Units”). We expect to issue approximately 7.1 million TLLP Common Units upon consummation of the Merger. No fractional TLLP Common Units will be issued in the Merger, and holders of QEPM Common Units other than QEPFS will instead receive cash in lieu of fractional TLLP Common Units, if any. Cash in lieu of fractional units will be the only cash component of the Merger. The Merger is expected to close in 2015 and is subject to customary closing conditions, including approval by the unaffiliated QEPM unitholders.

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.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

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 2% of our trade payables and 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 third-party 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 March 31, 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.

New Accounting Standards

Revenue Recognition. The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014, providing accounting guidance for all revenue arising from contracts to provide goods or services to customers. The requirements from the new ASU are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The FASB has proposed a one-year deferral of the effective date; however, this proposal has not been finalized. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the guidance to determine the method of adoption and the impact of this ASU on our financial statements and related disclosures.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Pushdown Accounting. The SEC released a Staff Accounting Bulletin (“SAB”) 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 Rockies Natural Gas Business Acquisition, we did not elect to apply pushdown accounting to certain acquired entities.

Treatment of Predecessor in EPU calculation. The Emerging Issues Task Force (“EITF”) reached a final consensus on Issue 14-A affirming their stance to require a master limited partnership to allocate earnings or losses of transferred net assets for periods prior to asset purchases from Tesoro entirely to the general partner when calculating earnings per unit (“EPU”). The final consensus is effective for interim and annual periods beginning after December 15, 2015 and early adoption is permitted. We have elected to adopt this guidance beginning in the first quarter of 2015. Adoption of the final consensus 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 months ended March 31, 2014 has been modified to conform to the requirements of the final consensus. There were no asset purchases from Tesoro during the three months ended March 31, 2015.

Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03 which will simplify the presentation of debt issuance costs. Under the new ASU, 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. This ASU 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 has 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 $47 million are recorded as a reduction to debt on the balance sheet as March 31, 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”). QEPFS also holds an approximate 55.8% limited partner interest in QEPM and 100% of the limited liability company interests of QEPM GP, which itself holds a 2% general partner interest and all of the incentive distribution rights (“IDRs”) in QEPM. 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.

Finalization of the purchase price allocation is pending and adjustments can be made through the end of TLLP’s measurement period, which is not to exceed one year from the acquisition date. During the three months ended March 31, 2015, the original purchase price was increased by $7 million for adjustments in net working capital primarily for changes related to accounts receivable as well as a change related to goodwill. We recorded $159 million of goodwill in connection with the Rockies Natural Gas Business Acquisition, of which $17 million was included in our Gathering segment, and $142 million 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 on our combined consolidated statements of operations. The gross carrying value of our intangibles was approximately $976 million and the accumulated amortization was approximately $10 million as of March 31, 2015. During the three months ended March 31, 2015, we incurred $7 million of amortization expense related to these intangibles.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the three months ended March 31, 2015, we incurred integration costs of $3 million related to the Rockies Natural Gas Business Acquisition. These costs are included in general and administrative expenses in our condensed statement of combined consolidated operations.

The table below reflects the preliminary acquisition date purchase price allocation as of March 31, 2015 (in millions):



Cash	$	31
Accounts receivable	120
Prepayments and other	7
Property, plant and equipment	1,735
Intangibles	976
Goodwill	159
Investment in unconsolidated affiliates	57
Other noncurrent assets	23
Accounts payable	(81		)
Other current liabilities	(47		)
Other noncurrent liabilities	(31		)
Noncontrolling interest	(432		)
Total purchase price	$	2,517

If the Rockies Natural Gas Business Acquisition had occurred on January 1, 2014, our pro forma revenues and net income would have been $225 million and $49 million, respectively, for the three months ended March 31, 2014.

2014 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 believe the terms and conditions under these agreements, as well as our other agreements with Tesoro, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

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.

Table of Contents

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.

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 March 31,
	2015		2014
Revenues (a)	$	148	$	111
Operating and maintenance expenses	25		20
Imbalance settlement gains and reimbursements from Tesoro (b)	8		7
General and administrative expenses	17		7

____________


(a)	Tesoro accounted for 56% and 88% of our total revenues for the three months ended March 31, 2015 and 2014, respectively.


(b)	Includes imbalance settlement gains of $2 million for both the three months ended March 31, 2015 and 2014. Also includes reimbursements primarily related to pressure testing and repairs and maintenance costs pursuant to the Amended Omnibus Agreement of $6 million and $5 million for the three months ended March 31, 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 months ended March 31, 2015 our general partner waived $2.5 million of general partner distributions with respect to IDRs. During the three months ended March 31, 2015, we paid quarterly cash distributions of $35 million to Tesoro and TLGP, including IDRs. On April 22, 2015, we declared a quarterly cash distribution of $0.6950 per unit, which will be paid on May 15, 2015. The distribution will include payment of $33 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 March 31, 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.

Effective May 16, 2014, all of the outstanding 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. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

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.

Table of Contents

TESORO LOGISTICS LP

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 March 31,
	2015			2014
Net income	$	74		$	42
Net income attributable to noncontrolling interest	(10		)	—
Net income, excluding noncontrolling interest (a)	64			42
General partner’s distributions (including IDRs) (b)	(14		)	(7		)
Limited partners’ distributions on common units	(56		)	(23		)
Limited partners’ distributions on subordinated units (c)	—			(9		)
Distributions less (greater) than earnings	$	(6	)	$	3

General partner’s earnings:
Distributions (including IDRs) (b)	$	14		$	7
Allocation of distributions less (greater) than earnings (a)	—			1
Total general partner’s earnings	$	14		$	8

Limited partners’ earnings on common units:
Distributions	$	56		$	23
Allocation of distributions less (greater) than earnings	(6		)	1
Total limited partners’ earnings on common units	$	50		$	24

Limited partners’ earnings on subordinated units (c):
Distributions	$	—		$	9
Allocation of distributions less (greater) than earnings	—			1
Total limited partners’ earnings on subordinated units	$	—		$	10

Weighted average limited partner units outstanding:
Common units - basic	80,250,208			39,186,006
Common unit equivalents	31,780			98,382
Common units - diluted	80,281,988			39,284,388

Subordinated units - basic and diluted (c)	—			15,254,890

Net income per limited partner unit:
Common - basic and diluted	$	0.63		$	0.64
Subordinated - basic and diluted	$	—		$	0.64

____________


(a)	In April 2015, the FASB ratified an EITF consensus on Issue 14-A 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 loss TLLP incurred during the three months ended March 31, 2014. See Note 1 for additional information on the new guidance.

(b)

General partner’s distributions (including IDRs) consist of an approximate 2% general partner interest and IDRs, which 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 (including IDRs) net of $2.5 million in IDRs 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.

Table of Contents

TESORO LOGISTICS LP

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):



	March 31, 2015			December 31, 2014
Gathering	$	1,558		$	1,507
Processing	541			539
Terminalling and Transportation	1,492			1,478
Other	26			27
Gross Property, Plant and Equipment	3,617			3,551
Accumulated depreciation	(282		)	(245		)
Net Property, Plant and Equipment	$	3,335		$	3,306

NOTE 6 - DEBT

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



	March 31, 2015			December 31, 2014
Total debt	$	2,563		$	2,588
Unamortized issuance costs (a)	(43		)	(44		)
Current maturities	—			—
Debt, net of current maturities and unamortized issuance costs	$	2,520		$	2,544

____________

(a) Includes unamortized premium of $4 million and $5 million as of March 31, 2015 and December 31, 2014, respectively.

Revolving Credit Facility

As of March 31, 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 $235 million of borrowings outstanding under the Revolving Credit Facility, resulting in a total unused loan availability of $665 million or 74% of the borrowing capacity as of March 31, 2015. The weighted average interest rate for borrowings under our Revolving Credit Facility was 2.67% at March 31, 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 March 31, 2015:



Credit Facility	30 day Eurodollar (LIBOR) Rate	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (b)	0.18%	2.50%	3.25%	1.50%	0.50%

____________

(b) 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.

Table of Contents

TESORO LOGISTICS LP

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 will accrue 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 $28 million and $32 million at March 31, 2015 and December 31, 2014, respectively. Expenditures of $4 million during the three months ended March 31, 2015 were related to the release of crude oil in Tioga, North Dakota.

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 had insurance recovery receivables of $16 million and $18 million related to the Crude Oil Pipeline Release at March 31, 2015 and December 31, 2014, respectively. These receivables are pursuant to a pollution liability insurance policy, which is subject to a $1 million deductible and a $25 million loss limit. The estimated remediation costs exceeded our policy loss limit by $17 million as of March 31, 2015 and December 31, 2014. Through March 31, 2015, we have received insurance proceeds of $9 million in reimbursements of costs incurred.

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.

Table of Contents

TESORO LOGISTICS LP

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 accordance with the sale and purchase agreements related to the Northwest Products System acquisition, as amended, Chevron retains financial and operational responsibility to remediate the site of the Diesel Pipeline Release through mid-2015, in addition to paying any monetary fines and penalties assessed by any government authority arising from this incident. In connection with the Northwest Products System acquisition, our condensed combined consolidated balance sheet included $6 million in accrued environmental liabilities at both March 31, 2015 and December 31, 2014.

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 $15 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. 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 March 31, 2015.

NOTE 8 - EQUITY

We had 52,423,925 common public units outstanding as of March 31, 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 March 31, 2015, which together constitutes a 36% ownership interest in us.

Table of Contents

TESORO LOGISTICS LP

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, 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 months ended March 31, 2015, we issued an aggregate of 446,499 common units under our ATM Program, generating net proceeds of approximately $24 million. The net proceeds from sales under the ATM Program are used for general partnership purposes.

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



	Partnership
	Common	General Partner	Total
Balance at December 31, 2014	80,125,930	1,631,448	81,757,378
Issuance of units under ATM Program	446,499	—	446,499
Unit-based compensation awards (a)	33,244	—	33,244
Balance at March 31, 2015	80,605,673	1,631,448	82,237,121

_____________


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

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	24			—			—			24
Distributions (b)	(54		)	(16		)	(9		)	(79		)
Net income attributable to partners	50			14			10			74
Contributions (c)	5			—			—			5
Other	1			—			—			1
Balance at March 31, 2015	$	1,500		$	(21	)	$	436		$	1,915

_____________

(b) Represents cash distributions declared and paid during the period ended March 31, 2015 relating to the fourth quarter of 2014.


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

Allocations of Net Income

Our partnership agreement contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss will be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions fully allocated to the general partner and any special allocations.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table presents the allocation of the general partner’s interest in net income (in millions, except percentage of ownership interest):



	Three Months Ended March 31,
	2015			2014
Net income, excluding noncontrolling interest and Predecessor	$	64		$	43
General partner’s IDRs (d)	(13		)	(6		)
Net income available to partners	$	51		$	37
General partner’s ownership interest	2.0		%	2.0		%
General partner’s allocated interest in net income	$	1		$	1
General partner’s IDRs (d)	13			6
Total general partner’s interest in net income	$	14		$	7

_____________


(d)	TLGP waived $2.5 million of their IDR’s in connection with the Rockies Natural Gas Business Acquisition for the three months ended March 31, 2015.

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 (e)

0.6950

May 15, 2015

May 4, 2015

_____________

(e) This distribution was declared on April 22, 2015 and will be paid on the date of distribution.

The allocation of total quarterly cash distributions to general and limited partners is as follows for the three months ended March 31, 2015 and 2014 (in millions). Our distributions are declared subsequent to quarter end; therefore, the table represents total cash distributions applicable to the period in which the distributions are earned.



	Three Months Ended March 31,
	2015		2014
General partner’s distributions:
General partner’s distributions	$	1	$	1
General partner’s IDRs (d)	13		6
Total general partner’s distributions	14		7

Limited partners’ distributions:
Common	56		23
Subordinated	—		9
Total limited partners’ distributions	56		32
Total Cash Distributions	$	70	$	39

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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;


•	140 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 and interest and financing costs 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, deposits and other assets that are not associated with a specific operating segment.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Segment information is as follows (in millions):



	Three Months Ended March 31,
	2015			2014
REVENUES
Gathering:
Affiliate	$	26		$	23
Third-party	51			2
Total Gathering	77			25
Processing
Affiliate	20			—
Third-party	47			—
Total Processing	67			—
Terminalling and Transportation:
Affiliate	102			88
Third-party	17			14
Total Terminalling and Transportation	119			102
Total Segment Revenues	$	263		$	127
OPERATING INCOME
Gathering	$	34		$	11
Processing	24			—
Terminalling and Transportation	62			53
Total Segment Operating Income	120			64
Unallocated general and administrative expenses	(12		)	(4		)
Interest and financing costs, net	(37		)	(18		)
Equity in earnings of unconsolidated affiliates	3			—
NET INCOME	$	74		$	42

CAPITAL EXPENDITURES
Gathering	$	51		$	18
Processing	1			—
Terminalling and Transportation	14			8
Total Capital Expenditures	$	66		$	26

Identifiable assets by operating segment were as follows (in millions):



Identifiable Assets	March 31, 2015		December 31, 2014
Gathering	$	1,733	$	1,694
Processing	1,653		1,612
Terminalling and Transportation	1,353		1,352
Other	57		107
Total Identifiable Assets	$	4,796	$	4,765

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 March 31, 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 March 31, 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 Green River Processing, LLC (“Green River Processing”) and QEPM. See page F-1 for Green River Processing’s separate financial statements and QEPM’s separate financial statements filed within its March 31, 2015 Form 10-Q (incorporated by reference as Exhibit 99.1 to this report). The separate condensed consolidating financial information is presented using the equity method of accounting for investments in subsidiaries.

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 months ended March 31, 2014.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Operations

for the Three Months Ended March 31, 2015

(In millions)



	Parent			Guarantor Subsidiaries			Non Wholly-owned Guarantors			Non-Guarantors			Eliminations			Consolidated
REVENUES
Affiliate	$	—		$	137		$	13		$	6		$	(8	)	$	148
Third-party	—			69			47			1			(2		)	115
Total Revenues	—			206			60			7			(10		)	263
COSTS AND EXPENSES
Operating and maintenance expenses	—			78			24			—			(8		)	94
Imbalance settlement gains and reimbursements from Tesoro	—			(8		)	—			—			—			(8		)
General and administrative expenses	6			13			6			—			—			25
Depreciation and amortization expenses	—			29			7			3			5			44
Total Costs and Expenses	6			112			37			3			(3		)	155
OPERATING INCOME (LOSS)	(6		)	94			23			4			(7		)	108
Interest and financing costs, net	(39		)	3			(1		)	—			—			(37		)
Equity in earnings of unconsolidated affiliates	—			1			2			—			—			3
Equity in earnings of subsidiaries	109			18			3			—			(130		)	—
NET INCOME	$	64		$	116		$	27		$	4		$	(137	)	$	74

Loss attributable to Predecessors	—			—			—			—			—			—
Net income attributable to noncontrolling interest	—			—			(9		)	(1		)	—			(10		)
Net income attributable to partners	$	64		$	116		$	18		$	3		$	(137	)	$	64

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Balance Sheet as of March 31, 2015

(In millions)



	Parent		Guarantor Subsidiaries		Non Wholly-owned Guarantors		Non-Guarantors		Eliminations			Consolidated
ASSETS
Current Assets
Cash and cash equivalents	$	3	$	3	$	7	$	3	$	—		$	16
Receivables, net
Trade	—		94		31		—		—			125
Affiliate	5		67		22		3		(21		)	76
Other	—		16		—		—		—			16
Prepayments and other	1		3		—		—		—			4
Total Current Assets	9		183		60		6		(21		)	237
Net property, plant and equipment	—		2,114		561		185		475			3,335
Intangibles	—		585		—		—		381			966
Goodwill	—		76		—		—		92			168
Investment in unconsolidated affiliates	—		18		25		—		16			59
Investments in subsidiaries	4,465		1,327		150		—		(5,942		)	—
Long-term intercompany receivable	—		565		—		2		(567		)	—
Other noncurrent assets	1		30		—		—		—			31
Total Assets	$	4,475	$	4,898	$	796	$	193	$	(5,566	)	$	4,796

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade	$	12	$	90	$	10	$	—	$	—		$	112
Affiliate	3		64		22		—		(21		)	68
Accrued interest and financing costs	62		—		—		—		—			62
Other current liabilities	22		35		2		—		(2		)	57
Total Current Liabilities	99		189		34		—		(23		)	299
Long-term intercompany payable	384		—		204		—		(588		)	—
Other noncurrent liabilities	—		41		29		1		(9		)	62
Debt, net of unamortized issuance costs	2,513		7		—		—		—			2,520
Equity - TLLP	1,479		4,661		498		150		(5,309		)	1,479
Equity - Noncontrolling interest	—		—		31		42		363			436
Total Liabilities and Equity	$	4,475	$	4,898	$	796	$	193	$	(5,566	)	$	4,796

Table of Contents

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
Intangibles	—		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.

Table of Contents

TESORO LOGISTICS LP

NOTES TO CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Condensed Consolidating Statement of Cash Flows

for the Three Months Ended March 31, 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	$	(4	)	$	153		$	25		$	5		$	(27	)	$	152
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures	—			(79		)	(3		)	—			—			(82		)
Investments in subsidiaries	(7		)	(3		)	—			—			10			—
Net cash used in investing activities	(7		)	(82		)	(3		)	—			10			(82		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from issuance of common units, net of issuance costs	24			—			—			—			—			24
Quarterly distributions to unitholders	(54		)	—			(9		)	—			9			(54		)
Quarterly distributions to general partner	(16		)	—			(1		)	(5		)	6			(16		)
Distributions to noncontrolling interest	—			—			(7		)	(2		)	—			(9		)
Distributions to subsidiaries	—			—			(10		)	—			10			—
Borrowings under revolving credit agreement	99			(9		)	9			—			—			99
Repayments under revolving credit agreement	(124		)	22			(22		)	—			—			(124		)
Contributions	—			7			3			—			(10		)	—
Intercompany borrowings (payments)	78			(86		)	3			3			2			—
Capital contributions by affiliate	7			—			—			—			—			7
Net cash from (used in) financing activities	14			(66		)	(34		)	(4		)	17			(73		)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	3			5			(12		)	1			—			(3		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	—			(2		)	19			2			—			19
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	3		$	3		$	7		$	3		$	—		$	16

Table of Contents

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. 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”).

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 includes a 55.8% 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”).

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.

OVERVIEW AND BUSINESS STRATEGY

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 the three months ended March 31, 2015, 56% of our total revenues were derived from Tesoro under various long-term, fee-based commercial agreements that generally include minimum volume commitments. We believe the terms and conditions under these agreements, as well as our other agreements with Tesoro, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

Our financial information includes the historical results of our Predecessor and the results of TLLP for the three months ended March 31, 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.

Table of Contents

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. With the exception of a nominal amount of condensate, 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. 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, these risks indirectly influence our activities and results of operations over the long term through their effects on our customers’ operations.

Rockies Natural Gas Business Acquisition. As a part of our strategy to focus on stable fee-based business, optimize existing assets, and grow through 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 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”).

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, within the Rockies and Bakken Regions, 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 new 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”). Subject to the satisfaction or waiver of certain conditions in the Merger Agreement, upon the later of the filing with the Secretary of State of the State of Delaware of a certificate of merger or the later date and time set forth in such certificate, Merger Sub will merge with and into QEPM, with QEPM surviving the merger as a wholly owned subsidiary of TLLP (the “Merger”). Following the Merger, QEPM GP will remain the general partner of QEPM, and all outstanding common units representing limited partnership interests in QEPM (the “QEPM Common Units”) other than QEPM Common Units held by QEPFS will be converted into the right to receive 0.3088 common units representing limited partnership interests in TLLP (the “TLLP Common Units”). We expect to issue approximately 7.1 million TLLP Common Units upon consummation of Merger. No fractional TLLP Common Units will be issued in the Merger, and holders of QEPM Common Units other than QEPFS will instead receive cash in lieu of fractional TLLP Common Units, if any. Cash in lieu of fractional units will be the only cash component of the Merger. The Merger is expected to close in 2015 and is subject to customary closing conditions, including approval by the unaffiliated QEPM unitholders.

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, located in the Williston/Bakken basin region of North Dakota and Montana, to transport crude oil from various points south of Lake Sakakawea, including TLLP’s Johnson’s Corner, Keane and Alexander Stations (all within McKenzie County, ND) to Ramberg Station, Williams County, ND. The original project scope required estimated capital expenditures of approximately $100 million. We did not receive sufficient commitments to move forward with the original project scope.

Based on shipper interest, as well as current demand for pipeline take-away capacity in the McKenzie County area of North Dakota, we intend to proceed with portions of the of the initial project in the core production areas in McKenzie County, ND. The smaller projects are expected to provide incremental capacity to move crude oil to our Ramberg Station for delivery to the Bakken Area Storage Hub as well as our interconnections with rail and new or expanded regional pipelines. The projects will require estimated capital expenditures of approximately $50 million and are expected to be completed in 2016.

Table of Contents

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 increase our distributions by 18% over the last year.

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:


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


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


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


•	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.

Non-GAAP Financial 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, depreciation and amortization expenses (“EBITDA”), Adjusted EBITDA and Distributable Cash Flow. We have updated our presentation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to now 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.

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 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 and 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.

Table of Contents

We believe that the presentation of EBITDA and adjusted EBITDA will provide useful information to investors in assessing our results of operations. 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 believe that the presentation of Distributable Cash Flow will provide useful information to investors as it is a widely accepted financial indicator used by investors to compare partnership performance, as it provides investors an enhanced perspective of the operating performance of our assets and the cash our business is generating. 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 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.

Table of Contents

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.

Combined Overview

The following table and discussion is a summary of our results of operations for the three months ended March 31, 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 Predecessors 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 March 31,
	2015			2014 (a)
REVENUES				(Includes Predecessor)
Gathering	$	77		$	25
Processing	67			—
Terminalling and Transportation (b)	119			102
Total Revenues	263			127
COSTS AND EXPENSES
Operating and maintenance expenses (c)	86			45
General and administrative expenses	25			10
Depreciation and amortization expenses	44			16
Gain on asset disposals and impairments	—			(4		)
Total Costs and Expenses	155			67
OPERATING INCOME	108			60
Interest and financing costs, net	(37		)	(18		)
Equity in earnings of unconsolidated affiliates	3			—
NET INCOME	$	74		$	42

Loss attributable to Predecessors	—			1
Net income attributable to noncontrolling interest	(10		)	—
Net Income attributable to Partners	64			43
General partner’s interest in net income, including incentive distribution rights	(14		)	(7		)
Limited partners’ interest in net income	$	50		$	36

Net income per limited partner unit:
Common - basic and diluted	$	0.63		$	0.64
Subordinated - basic and diluted	$	—		$	0.64

Weighted average limited partner units outstanding:
Common units - basic	80,250,208			39,186,006
Common units - diluted	80,281,988			39,284,388
Subordinated units - basic and diluted	—			15,254,890

EBITDA (d)	$	155		$	77
Adjusted EBITDA (d)	$	168		$	75
Distributable Cash Flow (d)	$	113		$	66

See pages 29 and 30 for footnotes to this table.

Table of Contents



	Three Months Ended March 31,
	2015			2014 (a)
Reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to Net Income:				(Includes Predecessor)
Net income	$	74		$	42
Loss attributable to Predecessors	—			1
Depreciation and amortization expenses, net of Predecessor expense	44			16
Interest and financing costs, net of capitalized interest	37			18
EBITDA (d)	$	155		$	77
Gain on asset disposals and impairments	—			(4		)
Billing of deficiency payments (e)	13			—
Inspection and maintenance capital expenses associated with the Northwest Products System	—			2
Adjusted EBITDA (d)	$	168		$	75
Interest and financing costs, net	(37		)	(18		)
Net income attributable to noncontrolling interest	(10		)	—
Maintenance capital expenditures (f)	(9		)	(2		)
Other adjustments for noncontrolling interest (g)	(8		)	—
Change in deferred revenue	5			—
Amortization of debt issuance costs	2			1
Reimbursement for maintenance capital expenditures (f)	1			—
Unit-based compensation expense	1			—
Proceeds from sale of assets	—			10
Distributable Cash Flow (d)	$	113		$	66

Reconciliation of EBITDA to Net Cash from Operating Activities:
Net cash from operating activities	$	152		$	69
Interest and financing costs, net	37			18
Changes in assets and liabilities	(32		)	(14		)
Amortization of debt issuance costs	(2		)	(1		)
Unit-based compensation expense	(1		)	—
Earnings from unconsolidated affiliates in excess of distributions	1			—
Predecessor impact	—			1
Gain on asset disposals and impairments	—			4
EBITDA (d)	$	155		$	77

____________


(a)	Includes the historical results related to the Partnership and Predecessor for the three months ended March 31, 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 include imbalance settlement gains of $2 million for both the three months ended March 31, 2015 and 2014. Also includes reimbursements primarily related to pressure testing and repairs and maintenance costs pursuant to the Amended Omnibus Agreement of $6 million and $5 million for the three months ended March 31, 2015 and 2014, respectively.


(d)	For a definition of EBITDA, Adjusted EBITDA and 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 2015, we invoiced customers for deficiency payments. We did not recognize $13 million of revenue related to the billing period as it represented opening balance sheet assets 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.

Table of Contents


(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) income attributable to noncontrolling interest and other adjustments for depreciation and maintenance capital expenditures applicable to the noncontrolling interests obtained in the December 2, 2014 Rockies Natural Gas Business Acquisition.

Summary

Our net income for the three months ended March 31, 2015 (“2015 Quarter”) increased $32 million to $74 million from $42 million for the three months ended March 31, 2014 (“2014 Quarter”). The increase in net income was primarily due to an increase in revenue of $136 million, or 107%, to $263 million driven by revenue generated under commercial agreements assumed and new commercial agreements entered into in conjunction with the Rockies Natural Gas Business Acquisition and the West Coast Logistics Assets Acquisition, respectively. The increase in revenue was partially offset by:


•	an increase in operating and maintenance expenses of $41 million, or 91%, 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 $28 million, as a result of depreciation on the assets acquired in the Rockies Natural Gas Business Acquisition;


•	an increase in net interest and financing costs of $19 million, primarily related an increase in outstanding debt in the 2015 Quarter principally as a result of 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 150%, primarily related to higher allocated overhead to support the Partnership’s growing business.

Table of Contents

Gathering Segment

The following table and discussion is an explanation of our results of operations of the Gathering segment for the three months ended March 31, 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 months ended March 31, 2015.



	Three Months Ended March 31,
	2015		2014
REVENUES
Crude oil gathering pipeline revenues	$	27	$	12
Crude oil gathering trucking revenues	14		13
Gas gathering revenues (a)	36		—
Total Revenues	77		25
COSTS AND EXPENSES
Operating and maintenance expenses (b)	23		11
General and administrative expenses	3		1
Depreciation and amortization expenses	17		2
Total Costs and Expenses	43		14
GATHERING SEGMENT OPERATING INCOME	$	34	$	11
VOLUMES (bpd)
Crude oil gathering pipeline throughput	155,882		97,991
Average crude oil gathering pipeline revenue per barrel (c)	$	1.95	$	1.34
Crude oil gathering trucking volume	45,926		44,701
Average crude oil gathering trucking revenue per barrel (c)	$	3.23	$	3.18
Gas gathering throughput (thousands of MMBtu/d) (a)	1,020		—
Average gas gathering revenue per MMBtu (c)	$	0.39	$	—

_____________


(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 for both of the three month periods ended March 31, 2015 and 2014.

(c)

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 March 31, 2015 Compared to Three Months Ended March 31, 2014

Volumes. Average crude oil gathering pipeline throughput volumes increased 57,891 bpd, or 59%, in the 2015 Quarter as a result of the expansion of our High Plains System and the assets acquired in the Rockies Natural Gas Business Acquisition, including a 51,456 bpd increase in third-party volumes. Crude oil gathering trucking throughput volumes increased 1,225 bpd, or 3%, during the 2015 Quarter due to increased volumes hauled by our proprietary fleet, partially offset by lower contract volume hauls. This shift to proprietary volumes is consistent with our strategy to expand the utilization of our proprietary fleet in order to generate cost and operating efficiencies. The increase in pipeline and trucking throughput reflects incremental volume on the High Plains Pipeline through the addition of new capacity associated with the High Plains Pipeline reversal completed in 2014. Average gas gathering volumes were 1,020 thousand MMBtu/d for the 2015 Quarter, which contributed approximately 47% of total Gathering segment revenue.

Table of Contents

Financial Results. Gathering revenues increased $52 million, or 208%, to $77 million for the 2015 Quarter compared to $25 million in the 2014 Quarter primarily as a result of the operation of the assets acquired in the Rockies Natural Gas Business Acquisition as well as higher crude oil pipeline and trucking throughput driven by our High Plains Pipeline reversal project, increased third-party volumes and higher utilization of our proprietary trucking fleet.

Operating and maintenance expenses increased $12 million, or 109%, to $23 million in the 2015 Quarter compared to $11 million in the 2014 Quarter primarily related to higher costs associated with the operation of the assets acquired in the Rockies Natural Gas Business Acquisition 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 months ended March 31, 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 months ended March 31, 2014.



	Three Months Ended March 31,
	2015
REVENUES
NGL processing revenues	$	20
Fee-based processing revenues	29
Other processing revenues	18
Total Revenues	67
COSTS AND EXPENSES
Operating and maintenance expenses	30
General and administrative expenses	2
Depreciation and amortization expenses	11
Total Costs and Expenses	43
PROCESSING SEGMENT OPERATING INCOME	$	24
VOLUMES
NGL processing throughput (bpd)	6,931
Average keep-whole fee per barrel of NGL (a)	$	31.84
Fee-based processing throughput (thousands of MMBtu/d)	689
Average fee-based processing revenue per MMBtu (a)	$	0.46

____________

(a)

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.

Three Months Ended March 31, 2015

Volumes. Average fee-based processing volumes were 689 thousand MMBtu/d and average NGL processing volumes totaled 6,931 bpd for the three months ended March 31, 2015.

Financial Results. Total processing revenues were $67 million contributing approximately 25% to the Partnership’s total revenues for three months ended March 31, 2015. Operating and maintenance expenses were $30 million in 2015, which represents approximately 35% to total operating and maintenance expenses for the three months ended March 31, 2015. Depreciation and amortization expense was $11 million in 2015, which represents approximately 25% of total depreciation and amortization expense for the three months ended March 31, 2015, and reflects depreciation associated with the acquisition of the Rockies Natural Gas Assets.

Table of Contents

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 months ended March 31, 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. 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 March 31,
	2015		2014
REVENUES			(Includes Predecessor)
Terminalling revenues (a)	$	90	$	76
Pipeline transportation revenues	29		26
Total Revenues	119		102
COSTS AND EXPENSES
Operating and maintenance expenses (b)	33		34
General and administrative expenses	8		5
Depreciation and amortization expenses	16		14
Gain on asset disposals and impairments	—		(4		)
Total Costs and Expenses	57		49
TERMINALLING AND TRANSPORTATION SEGMENT OPERATING INCOME	$	62	$	53
VOLUMES (bpd)
Terminalling throughput	917,549		901,328
Average terminalling revenue per barrel (a) (c)	$	1.10	$	0.93
Pipeline transportation throughput	818,317		817,177
Average pipeline transportation revenue per barrel (c)	$	0.39	$	0.36

____________


(a)	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.


(b)	Operating and maintenance expenses include imbalance settlement gains of $1 million for both of the three month periods ended March 31, 2015 and 2014.

(c)

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.

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Volumes. Terminalling throughput volumes increased 16,221 bpd, or 2%, in the 2015 Quarter compared to the 2014 Quarter primarily as a result of the operations acquired in the West Coast Logistics Asset Acquisition, which was partially offset by lower volumes at our Martinez, California marine terminal. Pipeline transportation throughput volumes increased 1,140 bpd in the 2015 Quarter compared to the 2014 Quarter due to growth in volumes as a result of the southern California distribution system projects.

Financial Results. Revenues increased $17 million, or 17%, to $119 million in the 2015 Quarter compared to $102 million in the 2014 Quarter primarily as a result of the new commercial agreements that went into effect in connection with the West Coast Logistics Assets Acquisition.

Table of Contents

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 requirements, long-term capital expenditure requirements, acquisition-related requirements and debt servicing requirements and allow us to fund at least the minimum quarterly cash distributions. In addition, we believe that these sources of liquidity will be sufficient to meet our obligation to fund the affiliate credit agreement with QEPM. For more information regarding the QEPM affiliate credit agreement see Note 1 of our Annual Report on Form 10-K for the year ended December 31, 2014.

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 (a)	0.6950		2.78		70		May 15, 2015	May 4, 2015

____________

(a) This distribution was declared on April 22, 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).

Table of Contents

Debt Overview

Our debt net of unamortized issuance costs of $2.52 billion, at March 31, 2015 is summarized as follows (in millions):



	March 31, 2015
Debt, including current maturities:	Principal		Unamortized Issuance Costs
Revolving Credit Facility	$	235	$	14
5.500% Senior Notes due 2019	500		7
5.875% Senior Notes due 2020	470		3
6.125% Senior Notes due 2021	550		8
6.250% Senior Notes due 2022	800		11
Capital lease obligations	8		—
Total Debt	$	2,563	$	43
Net Debt			$	2,520

Revolving Credit Facility

The Revolving Credit Facility was subject to the following expenses and fees at March 31, 2015:



Credit Facility	30 day Eurodollar (LIBOR) Rate	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (b)	0.18%	2.50%	3.25%	1.50%	0.50%

____________

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 March 31, 2015.

Table of Contents

Cash Flow Summary

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



	Three Months Ended March 31,
	2015			2014
Cash Flows From (Used In):
Operating Activities	$	152		$	69
Investing Activities	(82		)	(15		)
Financing Activities	(73		)	(34		)
Increase (decrease) in Cash and Cash Equivalents	$	(3	)	$	20

Operating Activities. Net cash from operating activities increased $83 million to $152 million in the 2015 Quarter compared to $69 million for the 2014 Quarter primarily due to a significant contribution 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 West Coast Logistics Asset Acquisition.

Investing Activities. Net cash used in investing activities for the 2015 Quarter increased $67 million to $82 million compared to $15 million in the 2014 Quarter. The increase related to this outflow was a result of higher capital expenditures in the 2015 Quarter 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 Quarter, including those reimbursed by our customers.

Financing Activities. Net cash used in financing activities for the 2015 Quarter was $73 million compared to $34 million for the 2014 Quarter. We paid higher quarterly cash distributions totaling $70 million during the 2015 Quarter compared to quarterly cash distributions totaling $36 million paid in the 2014 Quarter. Proceeds from the issuance of units under our ATM program of $24 million were offset by $25 million of net repayments under our Revolving Credit Facility during the 2015 Quarter. Additionally, we paid $9 million in distributions to the common public unitholders of QEPM during the 2015 Quarter.

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 months ended March 31, 2015 and 2014 (in millions):



	Three Months Ended March 31,
	2015		2014
Growth	$	57	$	24
Maintenance	9		2
Total Capital Expenditures	$	66	$	26

Table of Contents

The following table is a summary of our total 2015 expected capital expenditures, 2015 Quarter 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 Quarter Capital Expenditures		2015 Quarter Capital Expenditures, Net		Remaining 2015 Capital Expenditures		Remaining 2015 Capital Expenditures, Net
Growth	$	390	$	380	$	57	$	53	$	333	$	327
Maintenance	60		40		9		8		51		32
Total Capital Expenditures	$	450	$	420	$	66	$	61	$	384	$	359

We anticipate that our capital expenditures will be funded primarily with borrowings under our Revolving Credit Facility, issuances of additional debt and equity securities, cash generated from operations and reimbursements for certain maintenance and growth capital expenditures.

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 $112 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 Quarter we spent $23 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 and $4 million spent in the 2015 Quarter. 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.


•	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. In the 2015 Quarter we spent $5 million related to 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 estimated capital spend of $23 million and is expected to be operational in the second half of 2015. The estimated 2015 capital spend is $5 million with $3 million spent in the 2015 Quarter.


•	Projects to increase compression for our Pinedale, Vermillion and Uinta natural gas gathering systems and expand our gathering system in the Uinta basin.


•	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.

Table of Contents

Environmental Liabilities

Contamination resulting from spills of crude oil, natural gas and refined products is not unusual within the petroleum refining, terminalling, pipeline or natural gas gathering and 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 northwest products system acquisition.

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 $28 million and $32 million at March 31, 2015 and December 31, 2014, respectively. See Note 7 to our condensed combined consolidated financial statements for additional information regarding changes in environmental liabilities during the three months ended March 31, 2015.

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 had insurance recovery receivables of $16 million and $18 million related to the Crude Oil Pipeline Release at March 31, 2015 and December 31, 2014, respectively. These receivables are pursuant to a pollution liability insurance policy, which is subject to a $1 million deductible and a $25 million loss limit. The estimated remediation costs exceeded our policy loss limit by $17 million as of March 31, 2015. Through March 31, 2015, we have received insurance proceeds of $9 million in reimbursements of costs incurred.

Other Environmental Spending. We completed a detailed inspection and maintenance program in the 2015 Quarter, which included a total 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.

Table of Contents

Tesoro Indemnification

Under the Third Amended and Restated Omnibus Agreement (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.

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 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 $15 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. 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 March 31, 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.

Table of Contents

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 Shale/Williston Basin area of North Dakota and Montana (the “Bakken Region”);


•	a material decrease in the natural gas produced in the Green River Basin, Uinta Basin and Vermillion Basin in the states of Utah, Colorado and Wyoming (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 benefits, including, without limitation, expected accretion to our limited partners or operational synergies, of our transactions relating to our acquisition of QEP Resources’ wholly-owned subsidiary, QEPFS, our ability to integrate the acquired operations, or the value of the assets acquired in 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;


•	changes in the expected benefits of our transactions relating to our Acquisitions from Tesoro and third parties including the acquisitions of the West Coast Logistics Assets and the Rockies Natural Gas Assets;


•	changes in the timing, terms or potential structure of the proposed combination of the Partnership and QEPM;


•	changes in the expected spending related to the responsibility the Partnership assumed for performing testing and associated pipeline repairs pursuant to the Corrective Action Order in the Northwest Products System acquisition;


•	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;

Table of Contents


•	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 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.

Table of Contents

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 Tesoro could be impacted as a result of any changes in the spread between NGL sales prices and the price of natural gas.

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 March 31, 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 March 31, 2015 would change annual interest expense by less than $1 million. As of March 31, 2015, we had $235 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

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 March 31, 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.

Table of Contents

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 March 31, 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)
January 2015	13,233	$	54.66	—	$	—
February 2015	—	$	—	—	$	—
March 2015	—	$	—	—	$	—
Total	13,233			—

_____________


(a)	The entire 13,233 units were acquired from employees during the first quarter of 2015 to satisfy tax withholding obligations in connection with the vesting of performance phantom unit awards issued to them.

Table of Contents

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).

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.

*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.

99.1		Form 10-Q of QEP Midstream Partners, LP as of and for the period ended March 31, 2015 (incorporated by reference herein to QEP Midstream Partners, LP’s Quarterly Report on Form 10-Q filed on May 8, 2015, File 001-36047).

**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

Table of Contents

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:	May 8, 2015	By:	/s/ GREGORY J. GOFF
			Gregory J. Goff
			Chief Executive Officer
			(Principal Executive Officer)

Date:	May 8, 2015	By:	/s/ STEVEN M. STERIN
			Steven M. Sterin
			Vice President and Chief Financial Officer
			(Principal Financial Officer)

Table of Contents

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 subsidiary, Green River Processing, LLC (“Green River Processing”), pursuant to Rule 3-10 of Regulation S-X. At March 31, 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 Green River Processing, were elected guarantors of these obligations in January 2015. Stand-alone financial statements for Green River Processing are as follows:

GREEN RIVER PROCESSING, LLC

INDEX TO FINANCIAL STATEMENTS



FINANCIAL STATEMENTS	Page

Green River Processing Financial Statements (Unaudited)	F-2
Condensed Statements of Operations - Three Months Ended March 31, 2015 and 2014	F-2
Condensed Balance Sheets - March 31, 2015 and December 31, 2014	F-3
Condensed Statements of Cash Flows - Three Months Ended March 31, 2015 and 2014	F-4
Notes to Condensed Financial Statements	F-5
Green River Processing Management's Discussion and Analysis of Financial Condition and Results of Operations	F-9

F-1

Table of Contents

Green River Processing, LLC Financial Statements

GREEN RIVER PROCESSING, LLC

CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended March 31,
	2015		2014
	(in millions)
REVENUES
Third-party revenue	$	15	$	32
Affiliate revenue	11		7
Total Revenue	26		39
OPERATING EXPENSES
Processing expense	4		10
Transportation and fractionation costs	8		9
General and administrative	2		4
Depreciation and amortization	2		2
Total Operating Expenses	16		25
NET INCOME	$	10	$	14

See notes accompanying the condensed financial statements.

F-2

Table of Contents

GREEN RIVER PROCESSING, LLC

CONDENSED BALANCE SHEETS

(Unaudited)



	March 31,		December 31,
	2015		2014
	(in millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2	$	6
Accounts receivable, net	12		10
Accounts receivable from affiliate	16		11
Total Current Assets	30		27
NET PROPERTY, PLANT AND EQUIPMENT	276		278
Total Assets	$	306	$	305

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	7	$	10
Accounts payable to affiliate	15		10
Total Current Liabilities	22		20
Asset retirement obligation	5		5
COMMITMENTS AND CONTINGENCIES (NOTE 5)

EQUITY
Owners’ net investment	279		280
Total Equity	279		280
Total Liabilities and Equity	$	306	$	305

See notes accompanying the condensed financial statements.

F-3

Table of Contents

GREEN RIVER PROCESSING, LLC

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31,
	2015			2014
	(in millions)
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	10		$	14
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	2			2
Changes in operating assets and liabilities:
Accounts receivable	(7		)	(20		)
Accounts payable and accrued expenses	3			8
Other	—			(4		)
Net cash from operating activities	8			—

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures	(1		)	(1		)
Net cash used in investing activities	(1		)	(1		)

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Other capital contributions	6			1
Distributions to owners	(17		)	—
Net cash from (used in) financing activities	(11		)	1
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(4		)	—
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	6			—
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2		$	—
SUPPLEMENTAL CASH FLOW DISCLOSURE OF NON-CASH ACTIVITIES:
Change in capital expenditures included in accounts payable	$	1		$	—

See notes accompanying the condensed financial statements.

F-4

Table of Contents

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 formation of Green River Processing, the Assets were owned by Green River Processing Operations (“Green River Processing Operations”), which was also wholly-owned 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, including QEPFS, which was previously wholly-owned by QEPFSC. QEPFS owns 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”). As such, financial results reported for the three months ended March 31, 2014 (the “2014 Quarter”) 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 2014 Quarter was carved out from QEPFSC data as separate and distinct accounts for Green River Processing Operations have not been maintained. Financial data reported for the three months ended March 31, 2015 (the “2015 Quarter”) reflect results of operations under the management of TLLP and have been prepared from records owned and maintained by 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 2014 Quarter have been prepared from the historical accounting records owned and maintained by QEP Resources. Further, financial information for the 2015 Quarter was carved out from QEPFSC data as separate and distinct accounts for Green River Processing Operations have not been maintained. Financial results reported for the three months ended March 31, 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.

Green River Processing Operations is a limited liability company that is classified as a partnership for income tax purposes.

There were no assets or liabilities accounted for at fair value on a recurring basis as of March 31, 2015. Management believes the carrying value of our current assets and liabilities approximate fair value.

QEPFS and certain of its subsidiaries, including Green River Processing, were elected guarantors of TLLP’s registered 2020 5.875% Senior Notes and 2021 6.125% 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.

Transactions with QEP Resources and QEPFSC were considered related party for the three months ended March 31, 2014. For the three months ended March 31, 2015, transactions with QEPFS and TLLP are considered related party. See Note 2 for additional information.

F-5

Table of Contents

GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

Recent Accounting Developments

Revenue Recognition. The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 providing accounting guidance for all revenue arising from contracts to provide goods or services to customers. The requirements from the new ASU are effective for interim and annual periods beginning after December 15, 2016, and early adoption is not permitted. The FASB has proposed a one-year deferral of the effective date, however this proposal has not been finalized at this time. The standard allows for either full retrospective adoption or modified retrospective adoption. At this time, we are evaluating the guidance to determine the method of adoption and the impact of this ASU 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 months ended March 31, 2014. Subsequent to the Acquisition, including the three months ended March 31, 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, TRMC, Tesoro Logistics GP, LLC (“TLGP”), TLLP or any of TLLP’s subsidiaries (“Tesoro Entities”):



	Tesoro Entities		QEP Entities
	Three Months Ended March 31,
	2015		2014
	(in millions)

Revenue from affiliate	$	11	$	7
General and administrative	2		4

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 months ended March 31, 2014, or by TLLP for the three months ended March 31, 2015.

Allocation of Costs

The employees supporting Green River Processing’s operations were employees of QEPFSC and QEP Resources for the three months ended March 31, 2014 or TLGP, the general partner of TLLP, for the three months ended March 31, 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.

F-6

Table of Contents

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 Tesoro Refining & Marketing Company LLC (“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.

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.

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.

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 - PROPERTY, PLANT AND EQUIPMENT

A summary of the historical cost of Green River Processing’s property, plant and equipment is as follows:



	March 31, 2015			December 31, 2014
	(in millions)

Total property, plant and equipment	$	317		$	317
Accumulated depreciation	(41		)	(39		)
Total net property, plant and equipment	$	276		$	278

F-7

Table of Contents

GREEN RIVER PROCESSING, LLC

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 4 - EQUITY

Membership interest percentages as of March 31, 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	4			2			6
Distributions to owners	(10		)	(7		)	(17		)
Net income	6			4			10
Balance at March 31, 2015	$	168		$	111		$	279

NOTE 5 - COMMITMENTS AND CONTINGENCIES

Commitments

Green River Processing has an annual commitment under its Operating Agreement with QEPFS. See Note 2 for additional information.

Contingencies

Legal

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

F-8

Table of Contents

Green River Processing, LLC Management’s Discussion and Analysis

Overview

Green River Processing, LLC 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 QEP Field Services Company, which is a wholly-owned subsidiary of QEP Resources. Prior to formation of Green River Processing, the Assets were owned by Green River Processing Operations, which was also wholly-owned 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 QEP Midstream Partners, LP.

On December 2, 2014, Tesoro Logistics LP acquired QEP Resources’ midstream business, including QEP Field Services, LLC, which was previously wholly-owned by QEPFSC. QEPFS owns 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 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 (“Frac Spread”). 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 the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q 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.

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.

F-9

Table of Contents

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, for the three months ended March 31, 2014, 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 the 2014 Quarter through NGL sales are now earned under NGL processing agreements. As such, there were no NGL sales during the 2015 Quarter. See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q 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 2014 Quarter, or TLGP and TLLP for the 2015 Quarter. 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 2015 Quarter general and administrative costs primarily relate to services fees due to QEPFS under the Limited Liability Company Agreement of Green River Processing, LLC (the “Operating Agreement”). See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q for more information regarding this agreement.

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.

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.

Frac Spread

A portion of our operations are based on keep-whole processing agreements. Under our keep-whole processing agreements, we have historically been exposed to Frac Spread. In recent years, U.S. exploration and production companies have shifted capital to liquids-rich gas areas and caused NGL production to increase dramatically. Increased NGL production and price dislocations from infrastructure bottlenecks in certain regions have contributed to a weakening in NGL prices, particularly ethane. We expect that ethane prices will continue to be range-bound until new ethane cracking facilities are built. The prices of heavier components of the NGL barrel have weakened recently in conjunction with the decline in global crude oil prices. Effective December 2, 2014, Green River Processing entered into the Keep-Whole Commodity Agreement to mitigate on an annual basis the commodity price risk under these arrangements. See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q for more information regarding this agreement.

F-10

Table of Contents

Factors Affecting the Comparability of Our Financial Results

Green River Processing was organized in February 2014, and was initially wholly-owned by QEPFSC, a wholly-owned subsidiary of QEP Resources. Prior to formation of Green River Processing, the Assets were owned by Green River Processing Operations, which was wholly-owned by QEPFSC. In July 2014, QEPFSC conveyed the Assets 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 QEPM. In December 2014, QEPM was acquired by TLLP, including QEPFS, which owns 60% membership interest in Green River Processing and approximately 58% of general and limited partnership units of QEPM. As such, financial results reported for the 2014 Quarter 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 2014 Quarter was carved out from QEPFSC data as separate and distinct accounts for Green River Processing Operations have not been maintained. Financial data reported for the 2015 Quarter 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 2015 Quarter, 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.

F-11

Table of Contents

Results of Operations

The following table and discussion is an explanation of our results of operations for the three months ended March 31, 2015 and 2014 (in millions, except MMBtu/d, barrel per day, gallon, per MMBtu, per barrel and per gallon amounts).



	Three Months Ended March 31,
	2015		2014
	(in millions)
REVENUE
NGL sales (a)	$	—	$	22
NGL processing revenue (a)	11		—
Fee-based processing revenue	9		8
Other processing revenue (b)	6		9
Total Revenue	26		39
OPERATING EXPENSES
Processing expense	4		10
Transportation and fractionation costs (b)	8		9
General and administrative	2		4
Depreciation and amortization	2		2
Total Operating Expenses	16		25
NET INCOME	$	10	$	14
VOLUMES
NGL sales volumes (thousands of gallons)	—		13,778
Average NGL revenue per gallon of NGLs (c)	$	—	$	1.57
NGL processing throughput (bpd)	3,975		—
Average NGL revenue per barrel of NGL (c)	$	30.24	$	—
Fee-based processing throughput (thousands of MMBtu/d)	337		303
Average fee-based processing revenue per MMBtu of NGLs (c)	$	0.29	$	0.29

____________

(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 2014 Quarter through NGL sales are now earned under NGL processing agreements. As such, there were no NGL sales during the 2015 Quarter. See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q 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. These costs are shown as gross revenues and transportation and fractionation costs rather than as a net expense.

(c)

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). We calculate 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. Refer to note (a) regarding NGL sales; accordingly, there are no volumetric calculations associated with keep-whole agreements for the 2014 Quarter.

F-12

Table of Contents

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Volumes. Average fee-based processing volumes were 337 thousand MMBtu/d for the 2015 Quarter, which is consistent with the 303 thousand MMBtu/d for the 2014 Quarter. Average NGL processing volumes were 3,975 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 13,778 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 the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q for more information regarding the Keep-Whole Commodity Agreement.

Financial Results. Total processing revenues were $26 million for the 2015 Quarter, compared to $39 million for the 2014 Quarter. In the current year period, 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. The decline of $11 million from $22 million NGL sales in the 2014 Quarter to $11 million NGL processing revenue in the 2015 Quarter is a result of the transfer of the Company’s commodity risk exposure associated with keep-whole processing agreements to TRMC under the Keep-Whole Commodity Agreement. See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q for more information regarding the Keep-Whole Commodity Agreement. Fee-based processing revenues were $9 million for the 2015 Quarter, which is consistent with $8 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. These costs are shown as gross revenues and transportation and fractionation costs rather than as a net expense. In the 2015 Quarter, other processing revenues were $6 million, compared to $9 million in the 2014 Quarter. The decrease is due to higher fee-based NGL production in the 2014 Quarter.

Processing expenses were $4 million for the 2015 Quarter, compared to $10 million for the 2014 Quarter. There were no shrinkage costs in the 2015 Quarter under the Keep-Whole Commodity agreement as compared to the 2014 Quarter, which is the primary reason for the $6 million decrease. Transportation and fractionation costs, which are shown as gross revenues and transportation and fractionation costs rather than as a net expense, were $8 million in the 2015 Quarter. This is consistent with $9 million of these costs in the 2014 Quarter.

General and administrative expenses decreased $2 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 the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q 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 the service fee under QEP Resources for the 2014 Quarter and the service fee under the Operating Agreement.

Depreciation and amortization expense was $2 million for the 2015 Quarter, which is consistent with the 2014 Quarter.

F-13

Table of Contents

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.



	Three Months Ended March 31,
	2015			2014
	(in millions)
Cash Flows From (Used In):
Operating Activities	$	8		$	—
Investing Activities	(1		)	(1		)
Financing Activities	(11		)	1
Increase (Decrease) in Cash and Cash Equivalents	$	(4	)	$	—

Operating Activities. Net cash from operating activities increased to $8 million for the 2015 Quarter, compared to $0 million for the 2014 Quarter, primarily due to lower changes in working capital as compared to the 2014 Quarter.

Investing Activities. Net cash used in investing activities for the 2015 Quarter was consistent to the $1 million for the 2014 Quarter.

Financing Activities. Net cash used in financing activities for the 2015 Quarter was $11 million compared to the $1 million net cash increase for the 2014 Quarter. Contributions of $6 million made to the Company partially offsets the $17 million distributed to our members during the 2015 Quarter. As the Company was organized on February 6, 2014 and the Assets were not conveyed until July 1, 2014, there were no distributions during the 2014 Quarter. The $1 million contributed during the 2014 Quarter was made by QEP Resources, pursuant to the centralized cash management program. See Note 2 in the Non Wholly-Owned Guarantor Subsidiary Financial Statements of this Quarterly Report on Form 10-Q for additional information.

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-14

Attached files

Stock widget

Investing forum

ANDEAVOR LOGISTICS LP Reports