UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10‑K

(Mark One)

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

For the fiscal year ended December 31, 2018

or

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

For the transition period from ______________ to __________

Commission File Number 1‑35143

ANDEAVOR LOGISTICS LP

(Exact name of registrant as specified in its charter)

Delaware		27‑4151603
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
200 East Hardin Street, Findlay, Ohio 45840
(Address of principal executive offices) (Zip Code)
419-421-2414
(Registrant’s telephone number, including area code)

Securities registered pursuant to 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units Representing Limited Partnership Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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 o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer	þ	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	o
		Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

At June 30, 2018, the aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $3.8 billion based upon the closing price of its common units on the New York Stock Exchange Composite tape. The registrant had 245,551,332 common units outstanding at February 21, 2019.

DOCUMENTS INCORPORATED BY REFERENCE: None

Table of Contents

Andeavor Logistics LP

Annual Report on Form 10-K

Glossary of Terms		1
Important Information Regarding Forward-Looking Statements		4
Part I
Item 1 Business		5
	Terminalling and Transportation	8
	Gathering and Processing	10
	Wholesale	11
	Rate and Other Regulations	11
	Environmental Regulations	13
Item 1A Risk Factors		16
Item 1B Unresolved Staff Comments		33
Item 2 Properties		33
Item 3 Legal Proceedings		33
Item 4 Mine Safety Disclosures		33

Part II
Item 5 Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		34
Item 6 Selected Financial Data		35
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
	Business Strategy and Overview	37
	Results of Operations	38
	Capital Resources and Liquidity	52
	Accounting Standards	58
Item 7A Quantitative and Qualitative Disclosures about Market Risk		60
Item 8 Financial Statements and Supplementary Data		61
	Consolidated Statements of Operations	62
	Consolidated Balance Sheets	63
	Consolidated Statements of Partner’s Equity	64
	Consolidated Statements of Cash Flows	65
	Notes to Consolidated Financial Statements	66
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		101
Item 9A Controls and Procedures		101

Part III
Item 10 Directors, Executive Officers and Corporate Governance	103
Item 11 Executive Compensation	109
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	125
Item 13 Certain Relationships and Related Transactions, and Director Independence	126
Item 14 Principal Accountant Fees and Services	128

Part IV
Item 15 Exhibits and Financial Statement Schedules	129
Item 16 Form 10-K Summary	138
Signatures	139

This Annual Report on Form 10-K (including documents incorporated by reference herein) contains statements with respect to our expectations or beliefs as to future events. These types of statements are forward-looking and subject to uncertainties. Refer to our discussion of forward-looking statements in the section titled “Important Information Regarding Forward-Looking Statements.”

Additionally, throughout this Annual Report on Form 10-K, we have used terms in our discussion of the business and operating results that have been defined in our Glossary of Terms.

Glossary of Terms

Glossary of Terms

Throughout this Annual Report on Form 10-K, we have used the following terms:

2019 Secondment Agreements - MPLS Secondment Agreement and the MRLS Secondment Agreement.

AB 197 - California Assembly Bill 197.

ALRP - Andeavor Logistics Rio Pipeline LLC, a joint venture in which we have a 67% ownership interest.

Amended Omnibus Agreement - Fourth Amended and Restated Omnibus Agreement, as amended to date.

Andeavor Secondment Agreement - Secondment and Logistics Services Agreement with Andeavor, as amended and restated, which was terminated effective January 1, 2019.

ARO - Asset retirement obligations.

ASC 606- ASU 2014-09, “Revenue from Contracts with Customers,” and the associated subsequent amendments.

ASU - Accounting Standards Update.

Average crude oil and water gathering revenue per barrel - Calculated as total crude oil and water gathering fee-based revenue divided by crude oil and water gathering throughput presented in Mbpd multiplied by 1,000 and multiplied by the number of days in the period (365 days for the years endedDecember 31, 2018 and 2017, and 366 days for the year ended December 31, 2016).

Average gas gathering and processing revenue per MMBtu - Calculated as total gathering and processing fee-based revenue divided by gas gathering throughput presented in MMBtu/d multiplied by 1,000 and multiplied by the number of days in the period as outlined above.

Average margin on NGL sales per barrel - Calculated as the difference between the NGL sales revenues and the amounts recognized as NGL expense divided by our NGL sales volumes in barrels presented in Mbpd multiplied by 1,000 and multiplied by the number of days in the period as outlined above.

Average pipeline transportation revenue per barrel -Calculated as total pipeline transportation revenue divided by pipeline transportation throughput presented in Mbpd multiplied by 1,000 and multiplied by the number of days in the period as outlined above.

Average terminalling revenue per barrel - Calculated as total terminalling revenue divided by terminalling throughput presented in Mbpd multiplied by 1,000 and multiplied by the number of days in the period as outlined above.

Average wholesale fuel sales margin per gallon - Calculated as the difference between total wholesale fuel revenues and wholesale cost of fuel and other divided by our total wholesale fuel sales volume in gallons.

Bakken Region - Bakken Shale/Williston Basin area of North Dakota and Montana.

BLM - The Bureau of Land Management, an agency within the United States Department of Interior.

Board - Board of Directors of Tesoro Logistics GP, LLC.

Bpd - Barrels per day.

BTU - British thermal unit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

CERCLA - The Comprehensive Environmental Response, Compensation, and Liability Act of 1980.

Clean Water Act - The Federal Water Pollution Control Act of 1972.

Common carrier pipeline - A pipeline engaged in the transportation of crude oil, refined products or other hydrocarbon-based products as a common carrier for hire.

Distributable cash flow - Calculated as U.S. GAAP-based net cash flow from operating activities plus or minus changes in working capital, amounts spent on maintenance capital net of reimbursements and other adjustments not expected to settle in cash.

Distributable cash flow attributable to common unitholders - Calculated as distributable cash flow minus distributions associated with the Preferred Units.

Dropdown Credit Facility -Dropdown credit facility.

EBITDA - Net earnings before interest, income taxes, depreciation and amortization expenses.

End User - The ultimate user and consumer of transported energy products.

E&P - Exploration and Production.

EPAct - The Energy Policy Act of 1992.

EPA - The U.S. Environmental Protection Agency.

Exchange Act - The Securities Exchange Act of 1934, as amended.

FASB - Financial Accounting Standards Board.

FERC - Federal Energy Regulatory Commission.

Four Corners System - A pipeline system which includes pipelines in the San Juan Basin in the Four Corners area of Northwestern New Mexico that gather and transport crude oil and condensate produced in the Four Corners area and deliver it to Marathon’s Gallup refinery or to the TexNew Mex pipeline system.

December 31, 2018 |1

Glossary of Terms

Fractionation - The process of separating natural gas liquids into its component parts by heating the natural gas liquid stream and boiling off the various fractions in sequence from the lighter to the heavier hydrocarbons.

Gas processing - A complex industrial process designed to remove the heavier and more valuable natural gas liquids components from raw natural gas allowing the residue gas remaining after extraction to meet the quality specifications for long-haul pipeline transportation or commercial use.

High Plains System - Common carrier pipelines in North Dakota and Montana.

Homeland Standards - U.S. Department of Homeland Security Chemical Facility Anti-Terrorism Standards.

ICA - The Interstate Commerce Act of 1887.

IDR - Incentive distribution rights in Andeavor Logistics.

Initial Offering - Our initial public offering.

IFR - Interim Final Rule.

IRA - Individual retirement accounts.

IRS - Internal Revenue Service.

LARIP - Los Angeles Refinery Interconnect Pipeline.

LCFS - Low Carbon Fuel Standard.

MAPL - Mid-America Pipeline System.

Mbpd- Thousand barrels per day.

MPL - Minnesota Pipe Line Company, LLC, a joint venture in which we have a 17% common ownership interest.

MMBtu- Million British thermal units.

MMBtu/d- Million British thermal units per day.

MMcf- Million cubic feet. A cubic foot is a common unit of gas measurement. One standard cubic foot equals the volume of gas in one cubic foot measured at standard temperature (60 degrees Fahrenheit) and standard pressure (14.73 pounds standard per square inch).

MMcf/d- Million cubic feet per day.

MPC or Marathon - Marathon Petroleum Corporation.

MPC Loan Agreement - On December 21, 2018, we entered into a loan agreement with MPC.

MPLS - Marathon Petroleum Logistics Services LLC, an indirect, wholly-owned subsidiary of Marathon.

MPLS Secondment Agreement - Secondment Agreement between Marathon Petroleum Logistics Services LLC, the Partnership and certain of the Partnership’s subsidiaries.

MPLX - MPLX LP, a master limited partnership which has a general partner wholly owned by Marathon and of which Marathon holds 63.6% of the common units.

MRLS- Marathon Refining Logistics Services LLC, an indirect, wholly-owned subsidiary of Marathon.

MRLS Secondment Agreement - Secondment Agreement between Marathon Refining Logistics Services LLC, the Partnership and certain of the Partnership’s subsidiaries.

NAAQS - National Ambient Air Quality Standards.

NDPSC - North Dakota Public Service Commission.

NGA - The Natural Gas Act of 1938.

NGLs - Natural gas liquids.

NGPA - The Natural Gas Policy Act of 1978.

NMPRC - New Mexico Public Regulation Commission.

NSR/PSD - New Source Review/Prevention of Significant Deterioration.

NYSE - New York Stock Exchange.

OPA 90 - The Oil Pollution Act of 1990.

OPIS - Oil Price Information Service.

OSHA - The U.S. Occupational Safety Health Administration.

OSRO - Oil Spill Response Organizations.

PCAOB - Public Company Accounting Oversight

Board.

Permian Basin System - A pipeline system which includes the Delaware Basin system and other crude oil gathering assets in West Texas.

PHMSA- The Pipeline and Hazardous Materials Safety Administration.

PNAC - PNAC, LLC, a joint venture in which we have a 50% ownership interest.

POP - Percent of Proceeds.

ppb - parts per billion.

Preferred Units - 6.875% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests at a price to the public of $1,000 per unit.

RCRA - The Federal Resource Conservation and Recovery Act.

Refined products - Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

2 |

Glossary of Terms

Rendezvous Pipeline - Rendezvous Pipeline Company, LLC.

Revolving Credit Facility - Revolving credit facility.

RFS2 - Second Renewable Fuels Standard.

RGS -Rendezvous Gas Services, L.L.C., a joint venture in which we have a 78% interest.

Rockies Region - The Uinta Basin, Green River Basin and Vermillion Basin in the states of Utah, Colorado and Wyoming.

ROU - Right-of-use.

SB 32 - California Senate Bill 32.

SEC - Securities and Exchange Commission.

Segment EBITDA - Segment’s U.S. GAAP-based operating income before depreciation and amortization expense plus equity in earnings (loss) of equity method investments and other income (expense), net.

Special Allocation - Special allocation of net earnings.

Southwest System - Common carrier pipelines in New Mexico and Texas.

TexNew Mex Units - Andeavor Logistics TexNew Mex Units.

Throughput - The volume of hydrocarbon-based products transported or passing through a pipeline, plant, terminal or other facility during a particular period.

TLGP - Tesoro Logistics GP, LLC, our general partner.

TRC - Texas Railroad Commission.

Treasury Regulation - U.S. Treasury Regulation.

TRG - Three Rivers Gathering, L.L.C., a joint venture in which we have a 50% interest.

TRMC - Tesoro Refining and Marketing Company LLC.

UBFS - Uintah Basin Field Services, L.L.C., a joint venture in which we have a 38% interest.

Unit train- A train consisting of approximately one hundred rail cars containing a single material (such as crude oil) that is transported by the railroad as a single unit from its origin point to the destination, enabling decreased transportation costs and faster deliveries.

USCG - United States Coast Guard.

U.S. GAAP- Accounting principles generally accepted in the United States of America.

Western Refining - Western Refining, Inc.

Wholesale fuel sales per gallon- Calculated as wholesale fuel revenues divided by our total wholesale fuel sales volume in gallons.

December 31, 2018 |3

Important Information Regarding Forward Looking Statements

Important Information Regarding Forward-Looking Statements

This Annual Report on Form 10-K (including information incorporated by reference) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act, including, but not limited to, those under Item 1. Business, Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. All statements other than statements of historical fact, including without limitation statements regarding expectations regarding revenues, cash flows, capital expenditures, and other financial items, our business strategy, goals and expectations concerning our market position, future operations and profitability, are forward-looking statements. Forward-looking statements may be identified by use of the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will,” “would” and similar terms and phrases. Although we believe our assumptions concerning future events are reasonable, a number of risks, uncertainties and other factors could cause actual results and trends to differ materially from those projected, including, but not limited to:

• our ability to achieve expected coverage improvement and distributable cash growth;

• our ability to execute a funding model with no additional equity issuances and limited parent support;

• risks related to Marathon, including those related to Marathon’s acquisition of Andeavor or the potential merger, consolidation or combination of MPLX with us;

• changes in the expected value of and benefits derived from acquisitions, including any inability to successfully integrate acquisitions, realize expected synergies or achieve operational efficiency and effectiveness;

• the effects of changes in global economic conditions on our business, on the business of our key customers, and on our customers’ suppliers, business partners and credit lenders;

• a material change in the crude oil and natural gas produced in the basins where we operate;

• the ability of our key customers to remain in compliance with the terms of their outstanding indebtedness;

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

• regulatory and other requirements concerning the transportation of crude oil, natural gas, NGLs and refined products, particularly in the areas where we operate;

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

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

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

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

• changes in our cash flow from operations;

• changes in our tax status;

• the ability of our largest customers to perform under the terms of our gathering agreements;

• the risk of contract cancellation, non-renewal or failure to perform by those in our supply and distribution chains, and the ability to replace such contracts and/or customers;

• the suspension, reduction or termination of Marathon’s obligations under our commercial agreements and our secondment agreements;

• a material change in profitability among our customers;

• direct or indirect effects on our business resulting from actual or threatened terrorist or activist incidents, cyber-security breaches or acts of war;

• weather conditions, earthquakes or other natural disasters affecting operations by us or our key customers or the areas in which our customers operate;

• disruptions due to equipment interruption or failure at our facilities, Marathon’s facilities or third-party facilities on which our key customers are dependent;

• our inability to complete acquisitions on economically acceptable terms or within anticipated timeframes;

• actions of customers and competitors;

• changes in our credit profile;

• changes to our capital budget;

• 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 in obtaining necessary approvals and permits, compliance costs or other factors beyond our control;

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

• changes in capital requirements or in expected timing, execution and benefits of planned capital projects;

• seasonal variations in demand for natural gas and 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 Marathon;

• risks related to labor relations and workplace safety;

• political developments; and

• the factors described in greater detail under “Competition,” “Pipeline, Terminal and Rail Safety,” “Rate and Other Regulations” and “Environmental Regulations” in Item 1 and “Risk Factors” in Item 1A, and our other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

4 |

Business

Unless the context otherwise requires, references in this report to “Andeavor Logistics,” “the Partnership,” “we,” “us,” “our,” or “ours” refer to Andeavor 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 “Sponsor” refer collectively to Andeavor and any of Andeavor’s subsidiaries for all activity through September 30, 2018, or Marathon or any of Marathon’s subsidiaries including Andeavor LLC, successor-by-merger to Andeavor effective October 1, 2018 and a wholly owned subsidiary of Marathon, as applicable, other than Andeavor Logistics, its subsidiaries and its general partner. References in this report to “Marathon” or “MPC” refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries, including Andeavor LLC, or all of them taken as a whole.

Part I

Part 1 should be read in conjunction with Management’s Discussion and Analysis in Item 7 and our consolidated financial statements and related notes thereto in Item 8.

Item 1. Business

Andeavor Logistics is a leading growth-oriented, full-service, and diversified midstream company operating in the western and inland regions of the United States. We were formed by Andeavor and its wholly-owned subsidiary, TLGP, our general partner, in December 2010 as a Delaware master limited partnership to own, operate, develop and acquire logistics assets. The Partnership’s common units trade on the NYSE under the symbol “ANDX.”

We own and operate networks of crude oil, refined products and natural gas pipelines, terminals with crude oil and refined products storage capacity, rail loading and offloading facilities, marine terminals including storage, bulk petroleum distribution facilities, a trucking fleet and natural gas processing and fractionation complexes. Our assets are organized in three segments: Terminalling and Transportation, Gathering and Processing and Wholesale.

The following provides an overview of our assets and operations in relation to certain of Marathon’s refineries:

December 31, 2018 |5

Business

On October 1, 2018, Marathon completed its acquisition of Andeavor in accordance with the Agreement and Plan of Merger, dated as of April 29, 2018, as amended, under which MPC acquired Andeavor (the “MPC Merger”). Following the MPC Merger, Marathon was the beneficial owner of 156 million common units out of 245 million common units outstanding in the Partnership as of October 1, 2018, representing a 64% limited partner interest. Marathon is also the beneficial owner of 100% of the equity interests of TLGP.

Following the closing of the MPC Merger, Marathon announced that it had begun to evaluate our financial business plans with the intent to move toward financial policies that are more consistent with the approach Marathon uses for its other controlled master limited partnership, MPLX. Marathon announced that this approach includes meaningfully higher distribution coverage, leverage levels at or below 4.0x EBITDA, no planned public equity issuances and independent sustainability with limited parent support. Marathon has also previously disclosed that it is assessing strategic options for us and MPLX, which could include MPLX acquiring us or the Partnership acquiring MPLX.

2018 Acquisitions

2018 Drop Down

On August 6, 2018, we acquired Permian, refining logistics and asphalt assets (the “2018 Drop Down”) from our Sponsor. These assets include gathering, storage and transportation assets in the Permian Basin; legacy Western Refining assets and associated crude terminals; the majority of Andeavor’s remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC. In addition, the Conan Crude Oil Gathering System and the LARIP were transferred at cost plus incurred interest. In conjunction with the 2018 Drop Down, we entered into additional commercial agreements with our Sponsor. Refer to our discussion of the 2018 Drop Down, including financial details relating to the 2018 Drop Down, in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and the notes to our consolidated financial statements in Item 8 - Financial Statements and Supplementary Data.

The 2018 Drop Down includes:

• Crude oil and other feedstock storage tankage and refined product storage tankage at Marathon’s Mandan, Salt Lake City and Los Angeles refineries;

• Rail terminals and truck racks at Marathon’s Mandan, Salt Lake City and Los Angeles refineries for the loading and unloading of various refined products from manifest and other railcars and trucks, respectively;

• Interconnecting pipeline facilities in the Los Angeles area as well as other railroad tracks and adjoining lands;

• Mesquite and Yucca truck unloading stations in New Mexico for the unloading of crude trucks and injection of crude into the TexNew Mex pipeline;

• Mason East and Jackrabbit (“Wink”) truck unloading and injection stations in Texas that receive crude via the T-Station line and trucks for injection into the Kinder Morgan and Bobcat Pipeline;

• The Jal storage, injection and rail unloading facility in New Mexico that stores and supplies NGLs for use in Marathon’s El Paso refinery;

• NGL storage tankage, a rail and truck terminal for the loading and unloading of natural gas liquids from railcars and trucks as well as from the waterline at the Wingate facility in New Mexico;

• Crude oil and other feedstock storage tankage at the Clearbrook terminal in Minnesota;

• Bobcat Pipeline that transports crude oil between the Mason East Station and the Wink Station;

• Benny Pipeline that delivers crude oil from the Conan terminal in Texas to a connection with gathering lines in New Mexico;

• All of the issued and outstanding limited liability company interests in: (i) Tesoro Great Plains Midstream LLC, which owns BakkenLink Pipeline LLC, (ii) Andeavor MPL Holdings LLC, which holds the investment in MPL, (iii) Andeavor Logistics CD LLC, (iv) Western Refining Conan Gathering, LLC, which owns the Conan Crude Oil Gathering System, (v) Western Refining Delaware Basin Storage, LLC, (vi) Asphalt Terminals LLC, which holds the investment in PNAC, and (vii) 67% of all of the issued and outstanding limited liability company interests in ALRP; and

• Certain related real property interests.

SLC Core Pipeline System

On May 1, 2018, we completed our acquisition of the SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System) from Plains All American Pipeline, L.P.The system consists of pipelines that transport crude oil to another third-party pipeline system that supply Salt Lake City area refineries, including Marathon’s Salt Lake City refinery.

6 |

Business

Commercial Agreements

Percentage of Affiliate and Third-Party Revenues by Operating Segment during 2018

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 to our consolidated financial statements in Item 8 for further discussion.

(b) The presentation of wholesale fuel sales was impacted by the adoption of ASC 606 on January 1, 2018. Beginning January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements were netted.

Affiliates

Affiliates accounted for $1.6 billion, or 67%, of our total revenues for the year ended December 31, 2018.

We have various long-term, fee-based commercial agreements with our Sponsor, under which we provide pipeline transportation, trucking, terminal distribution, storage services and coke handling services to our Sponsor. See Note 3 to our consolidated financial statements in Item 8 for additional information on our commercial agreements.

We process gas for certain producers under keep-whole processing agreements. Under a keep-whole arrangement, a producer transfers title to the processor the NGLs produced during gas processing, and in exchange, the processor delivers to the producer natural gas with a BTU content equivalent to the NGLs that would be removed. The nature of the transaction typically exposes the processor to commodity price risk. However, we maintain an agreement with our Sponsor that transfers the commodity price risk exposure associated with these keep-whole processing agreements to our Sponsor (the “Keep-Whole Commodity Agreement”). Under the Keep-Whole Commodity Agreement, our Sponsor pays us a fee in exchange for the NGLs, and delivers the replaced natural gas to the producers on our behalf. We pay our Sponsor a marketing fee in exchange for assuming the commodity risk. See Note 3 to our consolidated financial statements in Item 8 for additional information on our keep-whole agreements.

Third Parties

Third parties accounted for $791 million, or 33%, of our total revenues for the year ended December 31, 2018.

Working Capital

We fund our business operations through a combination of available cash and equivalents and cash flows generated from operations. In addition, we have available revolving lines of credit, an affiliate loan agreement with MPC (“MPC Loan Agreement”) and we may issue additional debt or equity securities for additional working capital or capital expenditures. See “Capital Resources and Liquidity” in Item 7 for additional information regarding working capital.

Employees

As of December 31, 2018, neither we, nor our subsidiaries, directly employ any employees. The employees that conduct our business are directly employed by subsidiaries of Marathon. We had over 2,100 employees performing services for our operations as of December 31, 2018, approximately 245 of whom are covered by collective bargaining agreements. Of these employees, approximately 6 are covered by a collective bargaining agreement that was set to expire on January 31, 2019, and is under a rolling extension while the parties work toward a new agreement, approximately 125 under an agreement expiring January 31, 2022 and approximately 115 under an agreement expiring on February 28, 2023.

December 31, 2018 |7

Business

Website Access to Reports and Other Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other public filings with the SEC are available, free of charge, on our website (http://www.andeavorlogistics.com) as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information contained on our website is not part of this Annual Report on Form 10-K. You may also access these reports on the SEC’s website at http://www.sec.gov.

Terminalling and Transportation

Our Terminalling and Transportation segment consists of the following assets and operations:

Asset	Number of Terminals	Location	Key Products Handled	Volume Source	Terminalling Throughput Capacity (Mbpd)	Storage Capacity (thousand barrels)	Pipeline Mileage (b)
Land Terminals	44	AK, AZ, CA, ID, MN, ND, NM, NV, TX, UT, WA	Crude Oil, Refined Products, Asphalt	Marathon, Third-Party	1,439	62,673	—
Marine Terminals	6	CA, MN, WA	Crude Oil, Refined Products	Marathon, Third-Party	2,124	2,900	—
Northwest Pipeline System	—	CO, ID, OR, UT, WA, WY	Crude Oil, Refined Products	Marathon, Third-Party	—	—	1,996
Southern California System	—	CA	Crude Oil, Natural Gas, Refined Product	Marathon, Third-Party	—	—	193
Kenai Pipeline	—	AK	Refined Products	Marathon	—	—	74
Salt Lake City Short-haul	—	UT	Crude Oil, Refined Products	Marathon	—	—	22
Northern California System	—	CA	Crude Oil, Refined Products	Marathon	—	—	14
St. Paul Park	—	MN	Crude Oil, Natural Gas	Marathon	—	—	13
Petroleum Coke Handling (a)	1	CA	Petroleum Coke	Marathon	—	—	—
	51				3,563	65,573	2,312

(a) Our Petroleum Coke handling facility has capacity of 2,600 metric tons per day.

(b) The pipeline mileage associated with our equity method investments is not included in the table. Our equity method investments are discussed below.

Our Terminalling and Transportation segment generates revenues by charging our customers fees for:

• providing storage services;

• transporting refined products including asphalt;

• delivering crude oil, refined products and intermediate feedstocks from vessels to refineries and terminals;

• loading and unloading crude oil transported by unit train to Marathon’s Anacortes refinery;

• loading and unloading from marine vessels and barges;

• transferring refined products from terminals to trucks, barges, rail cars and pipelines;

• providing ancillary services, ethanol blending and additive injection; and

• handling petroleum coke for Marathon’s Los Angeles refinery.

Certain equity method investments that contribute to our Terminalling and Transportation segment include investments in:

• MPL, which owns and operates an approximate 550 mile crude oil pipeline in Minnesota; and

• PNAC, which owns and operates an asphalt terminal in Nevada.

We typically enter into long-term contractual arrangements with customers for the provision of services. Many of these contracts have minimum volume commitments that must be met by the customer over a period of time. As of December 31, 2018, approximately 92% of our total shell capacity is dedicated. These commitments and dedications provide our Terminalling and Transportation business with stable, fee-based cash flow limiting the impact of seasonality on our business.

8 |

Business

Our Sponsor is our largest customer. We derived 92% of Terminalling and Transportation revenues from our Sponsor and its affiliates, most of which were derived from contracts that include minimum volume commitments, and have provided 57.7 million barrels of dedicated storage capacity for our Sponsor under various agreements.

Competition

Our competition primarily comes from independent terminal and pipeline companies, integrated petroleum companies, refining and marketing companies and distribution companies with marketing and trading arms. Competition in particular geographic areas is affected primarily by the volumes of refined products produced by refineries located in those areas, the availability of refined products and the cost of transportation to those areas from refineries located in other areas.

We may compete with third-party terminals for volumes in excess of minimum volume commitments under our commercial agreements with our Sponsor and third-party customers as other terminals and pipelines may be able to supply Marathon’s refineries or end user markets on a more competitive basis due to terminal location, price, versatility and services provided. If Marathon’s customers reduced their purchases of refined products from Marathon due to the increased availability of less expensive product from other suppliers or for other reasons, Marathon may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which would decrease our revenues.

Safety

Terminal Safety

Terminal operations are subject to regulations under OSHA and comparable state and local regulations. Our terminal facilities are operated in a manner consistent with industry safe practices and standards. The storage tanks that are at our terminals are designed for crude oil and refined products and are equipped with appropriate controls that minimize emissions and promote safety. Our terminal facilities have response and control plans, spill prevention and other programs to respond to emergencies. Our terminals are regulated under the Homeland Standards or Maritime Transportation Security Act, which are designed to regulate the security of high-risk chemical facilities.

Pipeline Safety

Our pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. The transportation and storage of refined products, natural gas and crude oil involve a risk that hazardous liquids or natural gas may be released into the environment, potentially causing harm to the public or the environment. The U.S. Department of Transportation, through the PHMSA and state agencies, enforces safety regulations governing the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations require the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the investigation of anomalies and, if necessary, corrective action. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

We may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our pipelines. These costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during such repairs. Additionally, if we fail to comply with PHMSA or comparable state regulations, we could be subject to penalties and fines. If future PHMSA regulations impose new regulatory requirements on our assets, the costs associated with compliance could have a material effect on our operations.

While we operate and maintain our pipelines consistent with applicable regulatory and industry standards, we cannot predict the outcome of legislative or regulatory initiatives, which could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to comply with new requirements, costs associated with compliance may have a material effect on our operations.

Rail Safety

Our rail operations are limited to loading and unloading rail cars at our facilities. Generally, rail operations are subject to federal, state and local regulations. We believe our rail car loading and unloading operations meet or exceed all applicable regulations.

December 31, 2018 |9

Business

Gathering and Processing

Our Gathering and Processing segment consists of the following assets and operations:

System	Location	Key Products Handled	Volume Source	Processing Throughput Capacity (MMcf/d)	Pipeline Mileage (b)
High Plains	MT, ND	Crude Oil	Marathon, Third-Party	—	1,119
Southwest	NM, TX	Crude Oil	Marathon, Third-Party	—	983
North Dakota (a)	ND	Crude Oil, Natural Gas, Produced Water	Marathon, Third-Party	170	897
Uinta Basin	CO, UT	Natural Gas	Marathon, Third-Party	650	631
Green River (a)	UT, WY	Crude Oil, Natural Gas	Marathon, Third-Party	850	619
Vermillion	CO, UT, WY	Natural Gas	Third-Party	57	482
				1,727	4,731

(a) We have a combined fractionation throughput capacity of 33.8 Mbpd at our Blacks Fork, Robinson Lake and Belfield complexes.

(b) The pipeline mileage associated with our equity method investments is not included in the table. Our equity method investments are discussed below.

Our Gathering and Processing segment generates revenues by charging our customers fees for:

• gathering and transporting crude oil, natural gas and produced water;

• operating storage facilities with tanks located in strategic areas;

• operating truck-based crude oil gathering; and

• processing gas under fee-based processing, keep-whole and POP agreements.

Certain equity method investments that contribute to our Gathering and Processing systems including investments in:

• ALRP, which operates a recently constructed 113 mile crude oil pipeline located in the Delaware and Midland basins in west Texas;

• RGS, which operates the infrastructure that transports gas along 312 miles of pipeline from certain fields to several re-delivery points, including natural gas processing facilities that are owned by Andeavor Logistics or a third party;

• TRG, which transports natural gas across 52 miles of pipeline to our natural gas processing facilities in the Uinta Basin; and

• UBFS, which operates 79 miles of gathering pipeline and gas compression assets located in the southeastern Uinta Basin.

We derived 48% of Gathering and Processing revenues from our Sponsor and its affiliates. We process gas for certain producers under keep-whole processing agreements. Approximately 40% of our processing throughput capacity is currently supported by long-term, fee-based processing agreements with minimum volume commitments.

Our natural gas operations are affected by seasonal weather conditions and certain access restrictions imposed by the BLM on federal lands to protect migratory and breeding patterns of native species. During the winter months, our customers typically reduce drilling and completion activities due to adverse weather conditions. Also, access restrictions imposed by the BLM reduce our ability to complete expansion projects and connect to newly completed wells. We mitigate these seasonal risks in affected areas through prudent planning and coordination with our customers to ensure expansion projects are completed prior to these periods.

Competition

Our common carrier crude oil gathering and transport systems consists of our High Plains System and Southwest System, which gather and transport crude oil into major regional takeaway pipelines and refining centers, which compete with a number of transportation companies for gathering and transporting crude oil produced in the Bakken Region and the Delaware and Midland Basins, respectively. We may also compete for opportunities to build gathering lines from producers or other pipeline companies. Other companies have existing pipelines that are available to ship crude oil and continue to (or have announced their intent to) expand their pipeline systems in the Bakken Region and the Delaware and Midland Basins. We also compete with third-party carriers that deliver crude oil by truck.

Although we compete for third-party shipments of crude oil on our High Plains System and Southwest System, our contractual relationship with our Sponsor under our High Plains transportation services agreement (the “High Plains Pipeline Transportation

10 |

Business

Services Agreement”), Southwest pipeline and gathering services agreement and our connection to Marathon’s refineries provide us a strong competitive position in the regions.

Our competitors for natural gas gathering and processing include other midstream companies and producers. Competition for natural gas volumes and processing is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to markets, location, available capacity, capital expenditures and fuel efficiencies. In addition to competing for crude oil and natural gas volumes, we face competition for customer markets, which is primarily based on the proximity of the pipelines to the markets, price and assurance of supply.

Safety

Our natural gas processing plants and operations are subject to safety regulations under OSHA and comparable state and local requirements. A number of our natural gas processing facilities are also subject to OSHA’s process safety management regulations and the EPA’s risk management plan requirements. Together, these regulations are designed to prevent or minimize the probability and consequences of an accidental release of toxic, reactive, flammable or explosive chemicals. A number of our facilities are also regulated under the Homeland Standards, which are designed to regulate the security of high-risk chemical facilities. Our natural gas processing plants and operations are operated in a manner consistent with industry safe practices and standards.

Wholesale

Our Wholesale segment includes the operations of several bulk petroleum distribution plants and a fleet of refined product delivery trucks that distribute commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. This business includes the operation of a fleet of finished products trucks that deliver a significant portion of the volumes sold by our Wholesale segment.

The Wholesale segment purchases petroleum fuels from our Sponsor’s refineries and from third-party suppliers. We have entered into a product supply agreement, as amended, with our Sponsor and certain of its affiliates, pursuant to which our Sponsor has agreed to sell, and we have agreed to buy, between 90% and 110% of 79 Mbpd of our Sponsor’s refined products based upon forecasts provided each month by us. The products are purchased according to a predetermined formula based upon OPIS or Platts indices on the day of delivery and the applicable terminal location. Our Sponsor will provide us margin shortfall support for non-delivered rack sales. The product supply agreement contains customary payment terms that may be extended if our net working capital requirements grow significantly over time.

In addition to our sales to our Sponsor and certain of its affiliates, our principal customers are retail fuel distributors and the mining, construction, utility, manufacturing, transportation, aviation and agricultural industries. Our sales and services to our Sponsor accounted for 29% of our fuel sales volumes for the year ended December 31, 2018.

As part of this fuel distributions business, we have entered into a fuel distribution and supply agreement with our Sponsor. Under this arrangement, we are required to sell and deliver to our Sponsor, and our Sponsor is required to purchase and accept delivery from us, 21 Mbpd of branded and unbranded motor fuels to our Sponsor retail and cardlock locations in the Southwest U.S. In exchange for the sale and delivery of branded and unbranded motor fuels, our Sponsor will pay us an amount equal to our product cost at each terminal, plus applicable taxes and fees, actual transportation costs and a margin of $0.03 per gallon. In the event that our Sponsor fails to purchase the committed volume of branded and unbranded motor fuels, our Sponsor will pay $0.03 per gallon for each gallon below the committed volume. Our Sponsor will receive a credit for excess volumes purchased in subsequent months to the extent that shortfall payments were made in the prior twelve months. Our net cost per gallon will be determined based on the prices paid under the product supply agreement.

Competition

Our competition primarily comes from other wholesale petroleum products distributors on product sales pricing and distribution services in the Southwest U.S.

Rate and Other Regulations

General Interstate Regulation

Our High Plains System, Northwest Pipeline System, Southwest System and other interstate pipelines are common carriers subject to regulation by various federal, state and local agencies. The FERC regulates interstate transportation on our crude oil transportation and gathering pipelines and Northwest Pipeline System under the ICA, the EPAct, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively, “Petroleum Pipelines”), be just and reasonable and non-discriminatory, and that we file such rates and terms and conditions of service with the FERC. Under

December 31, 2018 |11

Business

the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in Petroleum Pipelines paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. There are no pending challenges or complaints regarding our current tariff rates.

Certain interstate Petroleum Pipeline rates in effect at the inception of the EPAct are deemed to be just and reasonable under the ICA. These rates are referred to as grandfathered rates. Our rates for interstate transportation service on the Northwest Pipeline System are grandfathered. The FERC allows for an annual rate change under its indexing methodology, which applies to transportation on our High Plains System and Northwest Pipeline System.

We own a natural gas pipeline in Wyoming. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of interstate pipelines extends to such matters as rates, services, and terms and conditions of service; the types of services offered to customers; the certification and construction of new facilities; the acquisition, extension, disposition or abandonment of facilities; the maintenance of accounts and records; relationships between affiliated companies involved in certain aspects of the natural gas business; the initiation and continuation of services; market manipulation in connection with interstate sales, purchases or transportation of natural gas; and participation by interstate pipelines in cash management arrangements. The FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Under the NGA, the rates for service on interstate facilities must be just and reasonable and not unduly discriminatory. The FERC has granted the Rendezvous Pipeline market-based rate authority, subject to certain reporting requirements. If the FERC were to suspend Rendezvous Pipeline’s market-based rate authority, it could have an adverse impact on our revenue associated with the transportation service.

Intrastate Regulation

The intrastate operations of our pipelines are subject to regulation by the NDPSC, the Regulatory Commission of Alaska, the NMPRC and the TRC. Applicable state law requires that:

• pipelines operate as common carriers;

• access to transportation services and pipeline rates be non-discriminatory;

• transported crude oil volumes be apportioned without unreasonable discrimination if more crude oil is offered for transportation than can be transported immediately; and

• pipeline rates be just and reasonable.

Pipelines

We operate our crude oil gathering pipelines and the Northwest Pipeline System as common carriers pursuant to tariffs filed with the FERC, the NDPSC for the High Plains System, the NMPRC for the Four Corners System and the TRC and NMPRC for the Permian Basin System. The High Plains System offers tariffs from various locations in Montana and North Dakota to a variety of destinations, which are utilized by Marathon and various third parties. Our Sponsor has historically shipped the majority of the volumes transported on the High Plains System, which is expected to continue in 2019. The Northwest Pipeline System extends from Salt Lake City, Utah to Spokane, Washington and offers tariffs from various locations to a variety of destinations, which serves both third-party customers and Marathon. We have additional pipelines that provide gathering of condensate in Wyoming and other pipelines that provide crude oil gathering in North Dakota.

The FERC and state regulatory agencies generally have not investigated rates on their own initiative absent a protest or a complaint by a shipper. Our Sponsor has agreed not to contest our tariff rates for the term of our commercial agreements. However, our pipelines are common carrier pipelines, and we may be required to accept additional third-party shippers who wish to transport through our system. The FERC, NDPSC, NMPRC or TRC could investigate our rates at any time. If an interstate rate for service on our pipelines were investigated, the challenger would have to establish that there has been a substantial change since the enactment of the EPAct, in either the economic circumstances or the nature of the service that formed the basis for the rate. If our rates are investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs.

Section 1(b) of the NGA exempts natural gas gathering facilities from the FERC’s jurisdiction. Although the FERC has not made formal determinations with respect to all of the facilities we consider to be gathering facilities, we believe that our natural gas pipelines meet the FERC’s traditional tests to determine that they are gathering pipelines and are, therefore, not subject to FERC jurisdiction.

States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based regulation. Our natural gas and crude oil gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas or crude oil without undue discrimination as to source of supply or producer. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas or crude oil. Failure to comply

12 |

Business

with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

Environmental Regulations

General

Our operations of pipelines, terminals and associated facilities in connection with the storage and transportation of crude oil, refined products and biofuels as well as our operations of gathering, processing and associated facilities related to the movement of natural gas are subject to extensive and frequently-changing federal, state and local laws, regulations, permits and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern obtaining and maintaining construction and operating permits, the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid, liquid, salt water and hazardous wastes and the remediation of contamination. Compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. These requirements may also significantly affect our customers’ operations and may have an indirect effect on our business, financial condition and results of operations. However, we do not expect such effects will have a material impact on our financial position, results of operations or liquidity.

Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, Marathon 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 the subsequent acquisitions from our Sponsor. See Note 10 to our consolidated financial statements in Item 8 for additional information regarding the Amended Omnibus Agreement and Carson Assets Indemnity Agreement.

Air Emissions and Climate Change Regulations

Our operations are subject to the Clean Air Act and comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies may be required to be installed at our facilities and our ability to secure future permits may become less certain. Any such future obligations could require us to incur significant additional capital or operating costs.

The EPA has undertaken significant regulatory initiatives under authority of the Clean Air Act’s NSR/PSD program in an effort to further reduce emissions of volatile organic compounds, nitrogen oxides, sulfur dioxide, and particulate matter. These regulatory initiatives have been targeted at industries with large manufacturing facilities that are significant sources of emissions, such as refining, paper and pulp, and electric power generating industries. The basic premise of these initiatives is the EPA’s assertion that many of these industrial establishments have modified or expanded their operations over time without complying with NSR/PSD regulations adopted by the EPA that require permits and new emission controls in connection with any significant facility modifications or expansions that can result in emission increases above certain thresholds. As part of this ongoing NSR/PSD regulatory initiative, the EPA has entered into consent decrees with several refiners, including Andeavor, that require the refiners to make significant capital expenditures to install emissions control equipment at selected facilities. However, we do not expect any additional requirements will have a material impact on our financial position, results of operations or liquidity.

The EPA strengthened the NAAQS for ground-level ozone to 70 ppb in 2015 from the 75 ppb level set in 2008. To implement the revised ozone NAAQS, all states will need to review their existing air quality management infrastructure State Implementation Plan for ozone and ensure it is appropriate and adequate. Where areas remain in ozone non-attainment, or come into ozone non-attainment as a result of the revised NAAQS, it is likely that additional planning and control obligations will be required. States may impose additional emissions control requirements on stationary sources, changes in fuels specifications, and changes in fuels mix and mobile source emissions controls. The ongoing and potential future requirements imposed by states to meet the ozone NAAQS could have direct impacts on terminalling facilities through additional requirements and increased permitting costs, and could have indirect impacts through changing or decreasing fuel demand.

The Energy Independence and Security Act of 2007 created RFS2 requiring the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced in the U.S. to reach 36.0 billion gallons by 2022. The ongoing and increasing requirements for renewable fuels in RFS2 could reduce future demand for petroleum products and thereby have an indirect effect on certain aspects of our business, although it could increase demand for our ethanol and biodiesel fuel blending services at our truck loading racks.

Currently, multiple legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation. These include actions to develop national, state or regional programs, each of which could require reductions in our greenhouse gas emissions or those of Marathon and our other customers. The EPA amended in 2015 the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program, to include among other things a new Onshore Petroleum and Natural Gas Gathering and Boosting segment, that encompasses greenhouse gas

December 31, 2018 |13

Business

emissions from equipment and sources within the petroleum and natural gas gathering and boosting systems. In 2016, the EPA promulgated regulations regarding performance standards for methane emissions from new and modified oil and gas production and natural gas processing and transmission facilities, and in September 2018, proposed targeted improvements to these standards to streamline implementation of the rules. These and other legislative regulatory measures will impose additional burdens on our business and those of Marathon and our other customers.

Hazardous Substances and Waste Regulations

To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed. For instance, CERCLA, and comparable state laws, impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site.

Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a hazardous substance and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites. Costs for these remedial actions, if any, as well as any related claims are all covered by indemnities from our Sponsor to the extent the release occurred or existed before the close of the Initial Offering and subsequent acquisitions from our Sponsor. The Partnership is not currently engaged in any CERCLA-related claims.

We also generate solid and liquid wastes, including hazardous wastes that are subject to the requirements of the RCRA and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes, including wastes generated from the transportation and storage of crude oil, natural gas, NGLs and refined products. We are not currently required to comply with a substantial portion of the RCRA requirements because the majority of our facilities operate as small quantity generators of hazardous wastes by the EPA and state regulations. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. The Hazardous Waste Generator Improvements Rule of the EPA provides some additional flexibility for small generators but also increases certain recordkeeping and administrative burdens. Several states are now in the process of adopting this rule. Any additional changes in the regulations could increase our capital or operating costs.

We operate two salt water disposal wells located in North Dakota that are permitted under state regulations to accept produced water and fluids or waters from drilling and gas plant operations. These fluids are considered exempt from RCRA requirements per the E&P exemption. Changes to state or federal regulations regarding the E&P exemption or rules for the operation of disposal wells could impose additional burdens on our business.

We currently own and lease properties where crude oil, refined petroleum hydrocarbons and fuel additives, such as methyl tertiary butyl ether and ethanol, have been handled for many years by previous owners. At some facilities, hydrocarbons or other waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed or released wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including impacted groundwater), or to perform remedial operations to prevent future contamination to the extent we are not indemnified for such matters.

Water Pollution Regulations

Our operations can result in the discharge of pollutants, including chemical components of crude oil, natural gas, NGLs and refined products. Many of our facilities operate near environmentally sensitive waters, where tanker, pipeline and other petroleum product transportation operations are regulated by federal, state and local agencies and monitored by environmental interest groups. The transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions in some cases of the OPA 90, and in all cases to related state requirements. These requirements can subject owners of covered facilities to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar, or in some cases, more stringent laws.

Regulations under the Clean Water Act, OPA 90 and state laws also impose additional regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and state laws require containment to mitigate or

14 |

Business

prevent contamination of waters in the event of a crude oil, natural gas, NGLs or refined products overflow, rupture, or leak from above ground pipelines and storage tanks. The Clean Water Act requires us to maintain spill prevention control and countermeasure plans at our facilities with above ground storage tanks and pipelines. In addition, OPA 90 requires that most oil transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We maintain such plans, and where required have submitted plans and received federal and state approvals necessary to comply with OPA 90, the Clean Water Act and related regulations. Our crude oil, natural gas, NGLs and refined product spill prevention plans and procedures are frequently reviewed and modified to prevent crude oil, natural gas, NGLs and refined product releases and to minimize potential impacts should a release occur. At our facilities adjacent to water, federally certified OSROs are available to respond to a spill on water from above ground storage tanks or pipelines. We have contracts in place to ensure support from the respective OSROs for spills in both open and inland waters.

The OSROs are capable of responding to a spill on water equal to the greatest volume of the largest above ground storage tank at our facilities. Those volumes range from 5,000 barrels to 125,000 barrels. The OSROs have the highest available rating and certification from the USCG and are required to annually demonstrate their response capability to the USCG and state agencies. The OSROs rated and certified to respond to open water spills (which include those OSROs with which we contract at our marine terminals that have received the highest available rating and certification from the USCG) must demonstrate the capability to recover up to 50,000 barrels of oil per day and store up to 100,000 barrels of recovered oil at any given time. The OSROs rated and certified to respond to inland spills must demonstrate the capability to recover up to 7,500 barrels of oil per day and store up to 15,000 barrels of recovered oil at any given time.

At each of our facilities, we maintain spill-response capability to mitigate the impact of a spill from our facilities until either an OSRO or other contracted service providers can deploy, and our Sponsor has entered into contracts with various parties to provide spill response services augmenting that capability, if required. Our spill response capability at our marine terminals meets the USCG and state requirements to either deploy on-water containment equipment two times the length of a vessel at our dock or have smaller vessels available. Our spill response capabilities at our other facilities meet applicable federal and state requirements. In addition, we contract with various spill-response specialists to ensure appropriate expertise is available for such contingencies. We believe these contracts provide the additional services necessary to meet or exceed all regulatory spill-response requirements.

The Clean Water Act also imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. In certain locations, we contract with third parties for wastewater disposal. Our remaining facilities may have portions of their wastewater reclaimed by Marathon’s nearby refineries. In the event regulatory requirements change, or interpretations of current requirements change, and our facilities are required to undertake different wastewater management arrangements, we could incur substantial additional costs. The Clean Water Act and RCRA can both impose substantial potential liability for the violation of permits or permitting requirements and for the costs of removal, remediation, and damages resulting from such discharges. In addition, states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater.

Tribal Lands

Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. For example, the EPA has established a preconstruction permitting program for new and modified minor sources throughout Indian country, and new and modified major sources in nonattainment areas in Indian country. In addition, each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our gathering operations on such lands.

Hydraulic Fracturing

We do not conduct hydraulic fracturing operations, but substantially all of our customers’ natural gas and crude oil production requires hydraulic fracturing as part of the completion process. Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process is typically regulated by state oil and natural-gas commissions, but the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of the process.

If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines, which could reduce the volumes of crude oil and natural gas available to move through our gathering systems and processing facilities, which could materially adversely affect our revenue and results of operations.

December 31, 2018 |15

Risk Factors

Item 1A. Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, financial condition, results of operations and our cash flows could be materially adversely affected. In that case, we might not be able to pay distributions on our common or preferred units or the trading price of our common units could decline.

Risks Related to Our Business

Our operations and Marathon’s refining operations are subject to many risks and operational hazards, which may result in business interruptions and shutdowns of our or Marathon’s facilities and damages for which we may not be fully covered by insurance. If a significant accident or event results in a business interruption or shutdown, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and operational hazards inherent in transporting and storing crude oil and refined products, as well as the gathering, processing and treating of natural gas and the fractionation of NGLs, including:

• damages to pipelines, plants and facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters as well as acts of terrorism;

• damage to pipelines and other assets from construction, farm and utility equipment;

• damage to third-party property or persons, including injury or loss of life;

• mechanical or structural failures on our pipelines, at our facilities or at third-party facilities on which our operations are dependent, including Marathon’s facilities;

• ruptures, fires and explosions;

• leaks or losses of crude oil, natural gas, NGLs, refined products and other hydrocarbons or other regulated substances as a result of the malfunction of equipment or facilities;

• curtailments of operations relative to severe seasonal weather; and

• other hazards.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions, shutdowns of our facilities or harm to our reputation. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations. In addition, Marathon’s refining operations, on which our operations are substantially dependent, are subject to similar operational hazards and risks inherent in refining crude oil.

A significant portion of our operating responsibility also requires us to ensure the quality and purity of the products loaded at our terminals and pipeline connections. If our quality control measures fail, we may have contaminated or off-specification products commingled in our pipelines and storage tanks or off-specification product could be sent to public gas stations and other End Users. These types of incidents could result in product liability claims from our customers or other pipelines to which our pipelines connect. There can be no assurance that product liability against us would not have a material adverse effect on our business or results of operations or our ability to maintain existing customers or retain new customers.

Our current insurance coverage does not insure against all potential losses, and we could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance or failure by an insurer to honor its coverage commitments for an insured event could have a material adverse effect on our business, financial condition and results of operations. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Insurance companies may demand significantly higher premiums and deductibles as a result of market conditions. Certain insurance could also become unavailable or available only for reduced amounts of coverage, if there are significant changes in the number or financial solvency of insurance underwriters for the energy industry.

If we are unable to complete acquisitions on economically acceptable terms or within anticipated timeframes from Marathon or third parties, our future growth will be limited, and any acquisitions we make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.

Our growth strategy depends in part on acquisitions that increase distributable cash flow. If we are unable to make acquisitions from Marathon or third parties, our ability to grow our operations and increase cash distributions to our unitholders will be limited. Even if we do consummate acquisitions that we believe will be accretive, they may in fact decrease distributable cash flow as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. Additionally, regulatory agencies could require us to divest certain of our assets in order to consummate future acquisitions. We may not be able to consummate any of our expected acquisitions within our desired timeframes or at all. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly and

16 |

Risk Factors

unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

A material decrease in our customers’ profitability could materially reduce the volumes of crude oil, refined products, natural gas and NGLs that we handle, which could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

The volume of crude oil, refined products, natural gas and NGLs that we distribute and store at our terminals, transport and process depends substantially on Marathon’s and other customers’ profit margins, the market price of crude oil, natural gas, NGLs and other refinery feedstocks, and product demand. These prices are impacted by numerous factors beyond our control or the control of Marathon and other third-party customers. Such factors include product margins and the global supply and demand for crude oil, natural gas, NGLs, gasoline and other refined products.

A material decrease in the crude oil or natural gas produced could materially reduce the volume of crude oil gathered and transported by our High Plains System and Southwest System or the volume of natural gas gathered, processed, transported and fractionated by our Rockies and Bakken Region assets.

The volume of crude oil that we gather and transport on our High Plains System and Southwest System in excess of committed volumes depends on demand for crude oil. This depends, in part, on the availability of attractively-priced, high-quality crude oil produced in the Bakken Region and the Delaware and Midland Basins, respectively. Similarly, the volume of natural gas that we gather, process, and transport, and the volume of NGLs that we fractionate in our Rockies and Bakken Region assets depends on the volume of natural gas and NGLs produced in the Green River, Uinta and Williston basins. Adverse developments in these regions could have a significantly greater impact on our financial condition, results of operations and cash flows than those of our competitors because of our lack of geographic diversity and substantial reliance on several major customers. Accordingly, in addition to general industry risks related to these operations, we may be disproportionately exposed to risks in the area, including:

• the volatility and uncertainty of regional pricing differentials;

• the availability of drilling rigs for producers;

• weather-related curtailment of operations by producers and disruptions to truck gathering operations;

• the nature and extent of governmental regulation and taxation, including regulations related to the exploration, production and transportation of shale oil and natural gas, including hydraulic fracturing and natural gas flaring and rail transportation;

• the development of third-party crude oil or natural gas gathering systems that could impact the price and availability of crude oil or natural gas in these areas; and

• the anticipated future prices of crude oil, refined products, NGLs and natural gas in surrounding markets.

If as a result of any of these or other factors, the volume of crude oil, natural gas or NGLs available in these regions is materially reduced for a prolonged period of time, the volume of our throughputs and the related fees, could be materially reduced. In addition, the construction by third parties of new pipelines in areas in which we own or acquire rail loading or unloading facilities could impact the ability of our rail facilities to remain competitive, resulting in reduced throughput and fees.

If third-party pipelines or other midstream facilities connected to our crude oil, refined products, natural gas gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the quality specifications of such pipelines or facilities, our business, results of operations and financial conditions could be adversely effected.

Certain of our crude oil, refined products, natural gas gathering, processing and transportation systems connect to other pipelines or facilities owned and operated by third parties, such as the Dakota Access Pipeline and the Kern River Gas Transmission Company Pipeline, the Northwest Pipeline, the Rockies Express Pipeline, Mid-America Pipeline and others. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, weather damage, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or other operational issues. Reduction of capacities of these third-party pipelines could also result in reduced volumes transported on our pipelines. In addition, if our costs to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in cost occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process the products, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, results of operations and financial condition could be adversely affected.

Our business is impacted by environmental risks inherent in our operations.

Our operation of crude oil, refined products, natural gas and produced water pipelines, and terminals and storage facilities is inherently subject to the risks of sudden or gradual spills, discharges or other inadvertent releases of petroleum or other regulated or hazardous substances. Spills, discharges and inadvertent releases have previously occurred and could occur in the

December 31, 2018 |17

Risk Factors

future; these releases could occur or may already have occurred at our pipelines, our terminals and facilities, or any other facility to which we send or have sent wastes or by-products for treatment or disposal. In any such incident, we could be liable, in some cases regardless of fault, for costs and penalties associated with the remediation of such facilities under federal, state and local environmental laws or the common law. We may also be liable for personal injury, property damage or claims from third parties alleging contamination from spills or releases from our facilities or operations.

With respect to assets that we acquired from Andeavor, our indemnification for certain environmental liabilities under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement is generally limited to liabilities identified prior to the earlier of the date that Marathon no longer controls our general partner or five years after the date of purchase. Even if we are insured or indemnified against environmental risks, we may be responsible for costs or penalties to the extent our insurers or indemnitors do not fulfill their obligations to us. The payment of such costs or penalties could be significant and have a material adverse effect on our business, financial condition and results of operations.

Climate change and related legislation or regulation reducing emissions of greenhouse gases could require us to incur significant costs or could result in a decrease in demand for crude oil, refined products, natural gas and NGLs, which could adversely affect our business.

Currently, various legislative and regulatory measures to address reporting or reduction of greenhouse gas emissions have been adopted or are in various phases of discussion or implementation. Requiring reductions in greenhouse gas emissions could cause us to incur substantial costs to (1) operate and maintain our facilities, (2) install new emission controls at our facilities and (3) administer and manage any greenhouse gas emissions programs, including the acquisition or maintenance of emission credits or allowances. These requirements may also adversely affect the refinery, gas production and other operations of Marathon and our other customers, leading to an indirect adverse effect on our business, financial condition and results of our operations.

In California, the state legislature adopted SB 32 in 2016. SB 32 set a cap on emissions of 40% below 1990 levels by 2030 but did not establish a particular mechanism to achieve that target. The legislature also adopted a companion bill, AB 197, that most significantly directs the California Air Resources Board to prioritize direct emission reductions on large stationary sources. In 2017, the state legislature adopted AB 398 which provides direction and parameters on utilizing cap and trade after 2020 to meet the 40% reduction target from 1990 levels by 2030 specified in SB 32. In 2009, CARB adopted the LCFS, which requires a 10% reduction in the carbon intensity of gasoline and diesel by 2020 and additional reductions beyond 2020 are anticipated. Compliance is demonstrated by blending lower carbon intensity biofuels into gasoline and diesel or by purchasing credits. Compliance with each of the cap and trade and LCFS programs is demonstrated through a market-based credit system.

Requiring a reduction in greenhouse gas emissions and the increased use of renewable fuels could decrease demand for refined products, which could have an indirect, but material, adverse effect on our business, financial condition and results of operations. For example, the EPA has promulgated rules establishing greenhouse gas emission standards for new-model passenger cars, light-duty trucks and medium duty passenger vehicles. Concerns over climate change and related greenhouse gas emissions could affect demand for petroleum products as well as new energy technologies including electric vehicles, fuel cells and battery storage systems and transportation alternatives. Any of these developments, or new taxes or fees imposed on crude oil, natural gas or refined products to fund clean energy initiatives at the state or federal level, could have an indirect adverse effect on our business due to reduced demand for crude oil, refined products, natural gas and NGLs.

In addition, scientific studies have indicated that increasing concentrations of greenhouse gases in the atmosphere can produce changes in climate with significant physical effects, including increased frequency and severity of storms, floods and other extreme weather events that could affect our operations. Increased concern over the effects of climate change may also affect our customers’ energy strategies, consumer consumption patterns and government and private sector alternative energy initiatives, any of which could adversely affect demand for petroleum products and have a material adverse effect on our business, financial condition and results of operations.

Our assets and operations are subject to federal, state, and local laws and regulations relating to environmental protection and safety that could require us to make substantial expenditures.

Our assets and operations involve the transportation and storage of crude oil and refined products, as well as the gathering, conditioning, processing and treating of natural gas and the fractionation of NGLs, which are subject to increasingly stringent and frequently changing federal, state and local laws and regulations governing facility operations, the discharge of materials into the environment and operational safety matters. We also own or lease a number of properties that have been used to gather, transport, store or distribute natural gas, produced water, crude oil and refined products for many years, and many of these properties have been operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control and may have operated in prior periods when environmental practices were less rigorous. Our sites, including storage tanks, wharf and dock operations, pipelines, processing plants, dehydrators, compressor stations and facility loading racks are also subject to federal, state and local regulation of air emissions and wastewater discharges. We may be required to address the release of regulated substances into the environment or other conditions discovered in the future that require environmental response actions or remediation. To the extent not covered by insurance or an indemnity, responding to such

18 |

Risk Factors

conditions may cause us to incur potentially material expenditures for response actions, government penalties, claims for damages to natural resources, personal injury or property damage claims from third parties and business interruption.

In addition, we operate in and adjacent to environmentally sensitive waters where tanker, pipeline, rail car and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Transportation and storage of crude oil and refined products over and adjacent to water involves inherent risk and subjects us to the provisions of the Federal Oil Pollution Act of 1990 and state laws in U.S. coastal and states bordering inland waterways on which we operate, as well as international laws in the jurisdictions in which we operate. If we are unable to promptly and adequately contain any accident or discharge involving tankers, pipelines, rail cars or above ground storage tanks transporting or storing crude oil or refined products, we may be subject to substantial liability. In addition, the service providers that have been contracted to aid us in a discharge response may be unavailable due to weather conditions, governmental regulations or other local or global events. International, federal or state rulings could divert our response resources to other global events. In these and other cases, we may be subject to liability in connection with the discharge of crude oil, natural gas, or refined products into navigable waters.

PHMSA issued an IFR in 2016 establishing procedures for the authority to issue emergency orders to pipeline operators. This authority can be used by PHMSA to address unsafe conditions or practices that pose an imminent hazard to the public health and safety. There are also significant pipeline safety rulemakings under consideration by PHMSA including the Hazardous Liquid rule and Safety of Gas Transmission and Gathering Pipelines rule. The overall impact of these rules is uncertain as they have yet to be finalized.

Our business activities are subject to increasingly strict federal, state, and local laws and regulations that require our pipelines, compressor stations, terminals, processing complexes, fractionation plants and storage facilities to comply with extensive environmental, health and safety requirements regarding the design, installation, testing, construction, and operational management of our facilities. We could incur potentially significant additional expenses if any of our assets were found to be non-compliant. Additional proposals and proceedings that impact our industry are regularly considered by Congress, as well as by state legislatures and federal, regional and state regulatory commissions or agencies and courts. Environmental health and safety regulatory requirements have historically grown more stringent over time and any future environmental, health and safety requirements or changed interpretations of existing requirements may impose more stringent requirements on our assets and operations, which may require us to incur potentially material expenditures to ensure continued compliance. The violation of such requirements could subject us to administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, permit restrictions or revocation, and the issuance of injunctions that may limit our operations, subject us to additional operational constraints or prevent or delay construction of additional facilities or equipment. In addition, government disruptions, such as a U.S. government shutdown, may delay or halt the granting and renewal of permits, licenses and other items required by us and our customers to conduct our business. Any of the foregoing could have a material adverse effect on our business, financial condition, or results of operations.

Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may increase in the future.

Our pipelines, terminals, fractionator and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

We rely upon certain critical information systems for the operation of our business, and the failure of any critical information system, including a cyber-security breach, may harm our business.

We depend heavily on technology infrastructure and rely upon certain critical information systems for the effective operation of our business. These information systems include data networks, telecommunications, cloud-based information controls, software applications and hardware, including those that are critical to the operation of our pipelines, terminals, processing facilities and other operations. Our technology infrastructure and information systems are subject to damage or interruption from a number of potential sources including unauthorized intrusions, cyber-attacks, software viruses or other malware, natural disasters, power failures, employee error or malfeasances and other events. No cybersecurity or emergency recovery processes is failsafe, and if our safeguards fail or our data or technology infrastructure is compromised, the safety and efficiency of our operations could be materially harmed, our reputation could suffer, and we could face additional costs, liabilities, and costly legal challenges, including those involving privacy of customer data. In addition, legislation and regulation relating to cyber-security threats could impose additional requirements on our operations. Finally, we may be required to incur additional costs to modify or enhance our systems to prevent or remediate the types of cyber incidents that continue to evolve.

December 31, 2018 |19

Risk Factors

Our expansion of existing assets and construction of new assets may not increase revenue and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations and financial condition.

We continue to evaluate opportunities for organic expansion projects and the construction of additional assets, such as our terminal expansions, and our pipeline connections in the Bakken and Permian regions. If we undertake these projects, they may not be completed on schedule at the budgeted cost or at all. The expansion or construction of new pipelines, processing plants or terminals involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. Government disruptions, such as a U.S. government shutdown, may delay or halt the granting and renewal of permits, licenses and other items required for construction. Additionally, some pipeline construction projects have faced nationwide protests that have halted and delayed construction. If we are targeted for protests, it could materially affect our ability to carry out our capital projects. Construction is also impacted by the availability of specialized contractors and laborers and the price and demand for materials. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, we may not receive sufficient long-term contractual commitments from customers to provide the revenue needed to support such projects and we may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive such commitments or make such interconnections, we may not realize an increase in revenue for an extended period of time. We may also construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize, resulting in less than anticipated throughput and a failure to achieve our expected investment return, which could adversely affect our results of operations and financial condition and our ability to make distributions to our unitholders.

Our pipelines are subject to state regulation that could materially and adversely affect our operations and cash flows.

In addition to safety and environmental regulations, certain of our pipelines are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations and may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our operations and revenue.

Pipeline rate regulation, changes to pipeline rate-making rules, or a successful challenge to the pipeline rates we charge may reduce our revenues and the amount of cash we generate.

The FERC regulates the tariff rates for interstate movements and state regulatory authorities regulate the tariff rates for intrastate movements on our crude oil, refined product, natural gas, and NGLs pipeline systems. The regulatory agencies periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services.

The FERC’s primary rate-making methodology is currently price-indexing; if the methodology changes, the new methodology could result in tariffs that generate lower revenues and cash flow. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods and is not based on pipeline-specific costs. If the index falls, we will be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing could adversely affect our revenues and cash flow.

If a party with an economic interest were to file either a protest of our proposal for increased rates or a complaint against our existing tariff rates, or the if FERC or a state regulatory agency were to initiate an investigation of our existing rates, then our rates could be subject to detailed review. If our present rates are challenged by a shipper, or if our proposed rate increases were found to be in excess of levels justified by our cost of service, the FERC or a state regulatory agency could order us to reduce our rates. If our existing rates were found to be in excess of our cost of service, we could be ordered to reduce our rates prospectively and refund the excess we collected for as far back as two years prior to the date of the filing of a FERC complaint challenging the rates. Refunds could also be ordered for intrastate rates, but the refund periods vary under state laws. If any challenge to committed intrastate rates for priority service on our High Plains System tariffs were successful, Marathon’s minimum volume commitment under our High Plains System intrastate Transportation Services Agreement could be invalidated, and the intrastate volumes shipped on our High Plains System would be at the lower uncommitted tariff rate. Any such reductions may lower revenues and cash flows if additional volumes and / or capacity are unavailable to offset such rate reductions, adversely affecting our financial position, cash flows, and results of operations.

We cannot guarantee that the jurisdictional status of transportation on our pipelines and related facilities will remain unchanged. Should circumstances change, then current non-FERC jurisdictional transportation could be found to be FERC-jurisdictional. In that case, the FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs, delay the use of rates that reflect increased costs, and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the provisions of our High Plains Pipeline Transportation Services Agreement regarding our agreement to provide, and Marathon’s agreement to purchase, certain crude oil volume losses could be viewed as a preference to Marathon and could result in negation of that provision and possible penalties.

20 |

Risk Factors

A change in our natural gas-gathering assets, or a change in FERC policy, could increase regulation of our natural gas-gathering assets, which could materially and adversely affect our financial condition, results of operations and cash flows.

Natural gas gathering facilities are expressly exempted from the FERC’s jurisdiction under the NGA. Although the FERC has not made any formal determinations with respect to all of our natural gas-gathering facilities we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline, and are therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by the FERC on a case-by-case basis. If the FERC were to consider the status of an individual facility and properly determine that the facility or services provided by it are subject to regulation by the FERC under the NGA or the NGPA, then such regulation could decrease revenue, increase operating costs and, depending upon the facility in question, adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, a requirement to return certain profits (including charges collected for such service in excess of the rate established by the FERC), loss of the ability to charge market-based rates for FERC jurisdictional services and enjoinment from engaging in certain future activities, any of which could negatively impact our business.

We own an interstate gas pipeline company, Rendezvous Pipeline, which is regulated by the FERC as a transmission pipeline under the NGA. The FERC has approved market-based rates for Rendezvous Pipeline allowing it to charge rates that customers will accept. The FERC has also established rules, policies and practices across the range of its natural gas regulatory activities, including, for example, policies on open access transportation, construction of new facilities, market transparency, market manipulation, ratemaking, capacity release, segmentation and market center promotion, which both directly and indirectly affect our business, and could materially and adversely affect our operations and revenues.

If Marathon or other customers satisfy only their minimum obligations under our commercial agreements, or if we are unable to renew or extend, the various commercial agreements we have, our business, financial condition, results of operations, and ability to make distributions to our unitholders could be adversely impacted.

Our commercial agreements require Marathon and certain third-party customers to provide us with minimum throughput volumes at our terminals and on certain pipelines, but they are not obligated to use our services with respect to volumes of crude oil, natural gas or refined products in excess of the minimum volume commitments. Nothing prohibits Marathon or other customers from utilizing third-party terminals and pipelines to handle volumes above the minimum committed volumes. At certain of our locations, third-party terminals and pipelines may be able to offer services at more competitive rates or on a more reliable basis. In addition, the initial terms of Marathon’s obligations under those agreements range from five to ten years. If Marathon or other customers fail to use our facilities and services after expiration of those agreements and we are unable to generate additional revenues from third parties, our ability to make cash distributions to unitholders may be reduced.

If we are unable to diversify our customer base, or if Marathon or one of our significant customers does not satisfy its obligations under our agreements or significantly reduces the volumes we are hired to transport, process or store, our revenues would decline and our financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be adversely affected.

Our largest customer, Marathon, including transactions with Andeavor prior to the MPC Merger, accounted for 67% of our total revenues in the year ended December 31, 2018. We expect to derive a significant amount of our revenues from Marathon and other key customers for the foreseeable future. This customer concentration makes us subject to the risk of nonpayment, nonperformance, re-negotiation of terms or non-renewal by these major customers under our commercial agreements. Furthermore, any event in our areas of operation or otherwise that materially and adversely affects the financial condition, results of operations or cash flows of one of these major customers may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business risks of these major customers (including Marathon), some of which are related to the following:

• the risk of contract cancellation, non-renewal or failure to perform by their customers;

• disruptions due to equipment interruption or failure at their facilities or at third-party facilities on which their business is dependent;

• the timing and extent of changes in commodity prices and demand for their refined products, natural gas and NGLs, and the availability and market price of crude oil and other refinery feedstocks;

• their ability to remain in compliance with the terms of their outstanding indebtedness;

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

• state and federal environmental, economic, health and safety, energy and other policies and regulations and any changes in those policies and regulations;

December 31, 2018 |21

Risk Factors

• environmental incidents and violations and related remediation costs, fines and other liabilities; and

• changes in crude oil, natural gas, NGLs and refined product inventory levels and carrying costs.

Our ability to increase our non-Marathon third-party revenue is subject to numerous factors beyond our control, including competition from other logistics providers, and the extent to which we have available capacity when potential customers require it. For example, our High Plains System may be unable to compete effectively with existing and future third-party crude oil gathering systems and trucking operations in the Bakken Region. Our ability to obtain third-party customers on our High Plains System is also dependent on our ability to make further inlet connections from and outlet connections to third-party facilities and pipelines. There are also competitors in the area of our natural gas gathering and processing facilities, and we may be unable to compete effectively in obtaining new supplies of gas for these operations.

We may not be able to attract material third-party service opportunities. Our efforts to attract new customers may be adversely affected by our relationship with Marathon, our desire to provide services pursuant to fee-based contracts and Marathon’s operational requirements with respect to our assets. Our potential customers may prefer to obtain services under other forms of contractual arrangements, under which we could be required to assume direct commodity exposure.

Some of our gathering and processing agreements contain provisions that may reduce the cash flow stability that the agreements were designed to achieve.

Several of the gathering and processing agreements of the natural gas and crude oil gathering and processing operations contain minimum volume commitments that are designed to generate stable cash flows while also minimizing direct commodity price risk. Under these minimum volume commitments, customers agree to ship a minimum volume of natural gas on its gathering systems or to process a minimum volume of natural gas at its processing complexes over certain periods during the term of the agreement. In addition, certain of our gathering and processing agreements also include an aggregate minimum volume commitment over the total life of the agreement. In these cases, once a customer achieves its aggregate minimum volume commitment, any remaining future minimum volume commitments will terminate and the customer will then simply pay the applicable gathering or processing rate multiplied by the actual throughput volumes shipped or volumes processed.

If a customer’s actual throughput volumes are less than its minimum volume commitment for the applicable period, it must make a deficiency payment at the end of the applicable period. The amount of the deficiency payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the minimum volume commitment for the applicable period, multiplied by the applicable gathering or processing fee. To the extent that a customer’s actual throughput volumes or volumes processed are above or below its minimum volume commitment for the applicable period, several of the gathering and processing agreements with minimum volume commitments contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments in subsequent periods. Under certain circumstances, some or all of these provisions can apply in combination with one another. It is possible that the combined effect of these mechanisms could reduce revenue or cash flows from one or more customers in a given period.

We do not own all of the land on which our pipelines, processing plants and terminals are located, which could disrupt our operations.

We do not own all of the land on which our pipelines, terminals and natural gas gathering and processing assets are located, but rather obtain the rights to construct and operate our pipelines, processing plants and terminals on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the possibility of more burdensome terms and increased costs to retain necessary land use if our leases and rights-of-way lapse or terminate or it is determined that we do not have valid leases or rights-of-way. Our loss of these rights, including loss through our inability to renew leases or right-of-way contracts on satisfactory terms or at all, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Certain of our crude oil and natural gas gathering facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, BLM, and the Office of Natural Resources Revenue, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands, including drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our natural gas and oil gathering and transmission operations on such lands.

22 |

Risk Factors

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Our use of debt directly exposes us to interest rate risk. Variable-rate debt, such as borrowings under our revolving credit facilities, 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.

As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may impact the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

Our level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our debt obligations.

As of December 31, 2018, we had $5.0 billionaggregate principal amount of debt outstanding, and we may incur significant additional debt obligations in the future. Our existing and future indebtedness could adversely affect our business, financial condition, results of operations and cash flows, including, without limitation, impairing our ability to obtain additional financing for working capital, capital expenditures, acquisitions, debt service requirements or other general partnership purposes or our ability to make distributions to our unitholders. In addition, we will have to use a substantial portion of our cash flow to pay principal, premium (if any for our senior notes) and interest on the senior notes and our other indebtedness, which will reduce the funds available to us for other purposes. Our level of indebtedness will also make us more vulnerable to economic downturns and adverse industry conditions, and may compromise our ability to capitalize on business opportunities and to react to competitive pressures as compared to our competitors.

Marathon’s indebtedness and credit ratings could adversely affect our business, credit rating, ability to obtain credit in the future and ability to make cash distributions to unitholders.

Marathon must devote a portion of its cash flows from operating activities to service its indebtedness, and therefore cash flows may not be available for use in pursuing its growth strategy. Furthermore, in the event that Marathon were to default under certain of its debt obligations, there is a risk that Marathon’s creditors would attempt to assert claims against our assets during the litigation of their claims against Marathon. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. In the event these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially adversely affected.

Credit rating agencies considered, and are likely to continue considering, the debt ratings of our Sponsor when assigning our debt ratings because of such controlling holder’s ownership interest in us, the significant commercial relationships between our controlling holder and us, and our reliance on our controlling holder for a substantial portion of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Marathon, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make cash distributions to our unitholders.

We may not be able to obtain funding on acceptable terms or at all because of volatility and uncertainty in the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

The domestic and global financial markets and economic conditions could be disrupted and are volatile from time to time due to a variety of factors, including crude oil and natural gas prices, geoeconomic and geopolitical issues, unemployment rates, weak economic conditions and uncertainty in the financial services sector. In addition, there are fewer investors and lenders willing to invest in the debt and equity capital markets in issuances by master limited partnerships than there are for more traditionally structured corporations. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially or the availability of funds from these markets could diminish. The cost of obtaining funds from the credit markets may increase as many lenders and institutional investors increase interest rates, enact tighter lending standards, refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease, to provide funding to borrowers.

In addition, lending counterparties under existing revolving credit facilities and other debt instruments may be unwilling or unable to meet their funding obligations. Certain lenders may determine not to lend to us due to the industry in which we operate, or other factors beyond our control. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities, any of which could have a material adverse effect on our revenues and results of operations.

December 31, 2018 |23

Risk Factors

Our distributions may fluctuate, and we may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay quarterly distributions to our unitholders at current levels or to increase our quarterly distributions in the future.

The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things, the following:

• the volume of crude oil, natural gas, NGLs and refined products that we handle;

• the tariff rates with respect to volumes we transport on our pipelines (including whether such tariffs are for long-haul or short-haul segments);

• the terminalling, trucking, processing and storage fees with respect to non-pipeline volumes we handle;

• the mix of gathering, processing, transportation and storage services we provide; and

• prevailing economic conditions.

In addition, the actual amount of cash we have available for distribution will also depend on other factors, some of which are beyond our control, including:

• the amount of our operating expenses and general and administrative expenses, including reimbursements to or from Marathon with respect to those expenses and payment of an annual corporate services fee to Marathon;

• the amount of our capital expenditures;

• the volatility in capital markets at the time of new debt or equity issuances;

• the timing of distributions on new unit issuances relating to acquisitions;

• the cost of acquisitions, if any;

• our debt service requirements and other liabilities;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets;

• restrictions contained in our credit facilities and other debt service requirements;

• an uninsured catastrophic loss;

• the amount of cash reserves established by our general partner; and

• other business risks impacting our cash levels.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability. As a result, we may make cash distributions during periods when we record net losses, and we may not make cash distributions during periods when we record net earnings.

Our debt obligations and restrictions in our Revolving Credit Facility, Dropdown Credit Facility, senior notes, the MPC Loan Agreement and any future financing agreements could adversely affect our business, financial condition, results of operations, ability to make distributions to our unitholders and the value of our units.

We are dependent upon the earnings and cash flow generated by our operations to meet our debt service obligations and to allow us to make cash distributions to our unitholders.

Funds available for our operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt. Furthermore, the provisions of our Revolving Credit Facility, Dropdown Credit Facility and senior notes, and any other debt we incur, may restrict our ability to obtain future financing and our ability to expand business activities or pursue attractive business opportunities. They may also restrict our flexibility in planning for, and reacting to, changes in business conditions. Our debt obligations contain covenants that require us to maintain certain interest coverage and leverage ratios. Our Revolving Credit Facility, Dropdown Credit Facility and senior notes also contain covenants that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:

• make certain cash distributions;

• incur certain indebtedness;

• incur certain liens;

• engage in certain mergers or consolidations and transfers of assets; and

• enter into certain transactions with affiliates.

If our operating results are not sufficient to service any future indebtedness, we may reduce distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity. We may not be able to complete any of these actions on satisfactory terms or at all. Furthermore, a failure to comply with the provisions of our debt obligations could result in

24 |

Risk Factors

an event of default, which could enable our lenders to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, defaults under any other debt instruments we may have could be triggered, and our assets may be insufficient to repay such debt in full. As a result, the holders of our units could experience a partial or total loss of their investment.

Our business may be negatively impacted by work stoppages, slowdowns or strikes.

Any work stoppage by employees who provide services to us may have a negative impact on our business. Additionally, Marathon is a significant customer and any strike action or work stoppage at any of Marathon’s facilities may result in us only receiving the minimum volume commitments under certain contracts, which could negatively affect our results of operations, cash flows and financial condition.

We may be unsuccessful in integrating the operations of the assets we have acquired or may acquire in the future, or in realizing all or any part of the anticipated benefits of any such acquisitions.

From time to time, we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. The acquisition components of our growth strategy depend on the successful integration of acquisitions. We face numerous risks and challenges to successful integration of acquired businesses, including the following:

• the potential for unexpected costs, delays and challenges that may arise in integrating acquisitions into our existing business;

• limitations on our ability to realize the expected cost savings and synergies from an acquisition;

• challenges related to integrating acquired operations that have management teams and company cultures that differ from our own;

• challenges related to the integration of businesses that operate in new geographic areas, including difficulties in identifying and gaining access to customers in new markets;

• difficulties of managing operations outside of our existing core business, which may require development of additional skills and competencies; and

• discovery of previously unknown liabilities following an acquisition with the acquired business or assets for which we cannot receive reimbursement under applicable indemnification provisions.

Additionally, Marathon has previously announced that it is evaluating our financial business plans with the intent to move toward financial policies that are more consistent with its approach Marathon uses for its other controlled master limited partnership, MPLX. Marathon announced that this approach includes meaningfully higher distribution coverage, leverage levels at or below 4.0x EBITDA, no planned public equity issuances, and independent sustainability with limited parent support. Marathon has also previously disclosed that it is assessing strategic options for us and MPLX, which options could include MPLX acquiring us or the Partnership acquiring MPLX.

Marathon may suspend, reduce or terminate its obligations under our commercial agreements and our 2019 Secondment Agreements in some circumstances, which would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Our commercial agreements and 2019 Secondment Agreements with Marathon include provisions that permit Marathon to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include a material breach of the agreement by us and certain force majeure events that would prevent us from performing required services under the commercial agreements. With respect to many of our facilities, these events also include the possibility that Marathon may decide to permanently or indefinitely suspend refining operations at one or more of its refineries. Marathon has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us.

In the event of a force majeure event under the commercial agreements, Marathon’s and our obligations under these agreements will be proportionately reduced or suspended to the extent that we are unable to perform. Force majeure events include acts or occurrences that prevent services from being performed under the applicable agreement, such as:

• acts of God, fires, floods or storms;

• compliance with orders of courts or any governmental authority;

• explosions, wars, terrorist acts, riots, strikes, lockouts or other industrial disturbances;

• accidental disruption of service;

• breakdown of machinery, storage tanks or pipelines and inability to obtain or unavoidable delay in obtaining material or equipment; and

• similar events or circumstances, so long as such events or circumstances are beyond our reasonable control and could not have been prevented by our due diligence.

December 31, 2018 |25

Risk Factors

Any of these events could result in our no longer being required to transport or distribute Marathon’s minimum throughput commitments on our pipelines or terminals, respectively, and in Marathon no longer being required to pay the full amount of fees that would have been associated with its minimum throughput commitments. These actions could result in a reduction or suspension of Marathon’s obligations under one or more of our commercial agreements, which would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Risks Relating to Our Partnership Structure

As of the completion of the MPC Merger, Marathon owns our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has limited fiduciary duties, and it and its affiliates may have conflicts of interest with us and they may favor their own interests to the detriment of us and our common unitholders.

Marathon and its affiliates own a 64% interest in us and control our general partner. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in the manner that is beneficial to its owner, Marathon. Conflicts of interest may arise between Marathon and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including Marathon, over the interests of our common unitholders. These conflicts include the following situations:

• Neither our partnership agreement nor any other agreement requires Marathon to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Marathon to increase or decrease refinery production, connect our pipeline systems to third-party delivery points, shut down or reconfigure a refinery, or pursue and grow particular markets. Marathon’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Marathon;

• Marathon, as our largest customer, may have an economic incentive to cause us to not seek higher tariff rates, trucking fees or terminalling fees, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;

• Marathon may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

• Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting its liability and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

• Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

• Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

• Our general partner determines the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the amount of adjusted operating surplus in any given period;

• Our general partner determines which costs incurred by it are reimbursable by us;

• Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• Our general partner has limited and may continue to limit its liability regarding our contractual and other obligations;

• Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 75% of the common units, which could require unitholders to sell their common units at an undesirable time and price, potentially resulting in no return on their investment or a tax liability on the sale of their units;

• Our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our commercial agreements with our Sponsor; and

• Our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will generally not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such

26 |

Risk Factors

opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions. Our general partner’s discretion in establishing cash reserves may also reduce the amount of cash available for distribution to unitholders.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would increase interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

The partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of duty.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders.

Additionally, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

For example, our partnership agreement:

• provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, which requires that it believed that the decision was in, or not opposed to, the best interest of our partnership;

• provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal;

• provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is not approved by our conflicts committee or approved by a vote of a majority of outstanding common units, but is entered into in good faith by our general partner and is on terms no less favorable to us than those generally being provided to or available from unrelated third parties or fair and reasonable to us, taking into account the totality of the relationships among the parties involved; and

• provides that in resolving conflicts of interest, it is presumed that in making its decision the general partner acted in good faith and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.

Cost reimbursements and fees due our general partner and its affiliates for services provided are substantial and reduce our cash available for distribution to unitholders.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our

December 31, 2018 |27

Risk Factors

Amended Omnibus Agreement or our 2019 Secondment Agreements, our general partner determines the amount of these expenses. Under the terms of the Amended Omnibus Agreement, we are required to pay Marathon an annual corporate services fee, currently $17 million, for the provision of various centralized corporate services. Under the terms of our 2019 Secondment Agreements, we reimburse the applicable Marathon subsidiary for the payroll costs of the seconded employees, including base pay, bonuses and other incentive compensation plus a burden rate associated with benefits and other payroll costs for the portion of the employee’s time that is allocated to us. We reimburse Marathon for any direct costs actually incurred by Marathon in providing other operational services with respect to certain of our other assets and operations. Our general partner and its affiliates may also provide us other services for which we will be charged fees as determined by our general partner. Payments to our general partner and its affiliates are substantial and reduce the amount of available cash for distribution to unitholders.

Unitholders have very limited voting rights and, even if they are dissatisfied, their ability to remove our general partner without its consent is limited.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. The Board is chosen by the members of our general partner. Marathon is currently the beneficial owner of 100% of the equity interests of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, their ability to remove our general partner is limited. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Our general partner and its affiliates currently own approximately 64% of our outstanding common units and, as a result, our public unitholders cannot remove our general partner without its consent. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of our Board, cannot vote on any matter.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Marathon to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and to control the decisions taken by the Board and officers.

We may issue additional units without unitholder approval, including units that are senior to the common units and/or pari passu with our Preferred Units, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, neither our partnership agreement nor our credit facilities prohibits the issuance of equity securities that may effectively rank senior to our common units, including additional Preferred Units and any securities in parity with the Preferred Units without any vote of the holders of the Preferred Units (except where the cumulative distributions on the Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of our common units and Preferred Units may decline.

Additionally, although holders of the Preferred Units, like holders of our common units, are entitled to limited voting rights, with respect to certain matters the Preferred Units generally vote separately as a class along with all other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote. The issuance of additional units on parity with or senior to the Preferred Units (including additional Preferred Units of the same series) would dilute the interests of the holders of the Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (including additional Preferred Units of the same series) or equity securities with terms expressly made senior to the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or

28 |

Risk Factors

pay the liquidation preference on the Preferred Units. Only the change of control conversion right relating to the Preferred Units set forth in our partnership agreement protects the holders of the Preferred Units in the event of a highly leveraged or other transaction, including a merger or the sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of the Preferred Units.

The payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our Preferred Units in any fiscal quarter, we will be unable to pay distributions on our common units until all unpaid Preferred Unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.

The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. The preferences and privileges of the Preferred Units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Marathon may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of February 21, 2019, Marathon holds 156,173,128 common units. Additionally, Marathon holds certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units.

Affiliates of our general partner, including Marathon, may compete with us.

As a result of the MPC Merger, Marathon is the beneficial owner of 100% of the equity interests of our general partner, together with approximately 64% of our common units. With limited exceptions, Marathon and its affiliates are not restricted from competing with us. In addition, Marathon and certain other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from Marathon and other affiliates of our general partner could materially and adversely impact our results of operations and cash available for distribution to unitholders.

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. The unitholder could be liable for our obligations as if he were a general partner if a court or government agency were to determine that:

• we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• his right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute control of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units or Preferred Units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

December 31, 2018 |29

Risk Factors

Our unitholders who fail to furnish certain information requested by our general partner or who our general partner, upon receipt of such information, determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units or Preferred Units will be subject to redemption.

Our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish this information within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible U.S. citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units or Preferred Units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us under FERC regulations, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement gives our general partner the power to amend the agreement. If our general partner determines that we are not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s Board or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Tax Risks to Common Unitholders and Preferred Unitholders

Our tax treatment depends on our status as a partnership for federal and state income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were subjected to a material amount of additional entity-level taxation by individual states, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this.

It is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Additionally, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to unitholders.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

30 |

Risk Factors

The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time.

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income, which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units or Preferred Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units or Preferred Units could be more or less than expected.

A unitholder that sells units will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and the tax basis in those units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the tax basis in our common units, the amount, if any, of such prior excess distributions with respect to the common units sold will, in effect, become taxable income if sold at a price greater than the tax basis, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, if the partnership has nonrecourse liabilities, the amount realized includes a unitholder’s share of our nonrecourse liabilities. In that case, a unitholder selling common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units or Preferred Units that may result in adverse tax consequences to them.

Investment in common units or Preferred Units by tax-exempt entities, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. A tax-exempt entity or a non-U.S. person should consult a tax adviser before investing in our common units or Preferred Units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available. It could also affect the timing of these tax benefits or the amount of taxable income from the sale of common units and could have a negative impact on the value of our common units.

December 31, 2018 |31

Risk Factors

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units or Preferred Units are loaned to a short seller to affect a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units or Preferred Units are loaned to a short seller to effect a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

We have adopted certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It could also affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

As a result of investing in our common units or Preferred Units, unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. Many of the states in which we operate currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is the unitholder’s responsibility to file all federal, state and local tax returns.

If we are required to make payments of taxes, penalties, and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.

Recently enacted legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing partnerships and for assessing and collecting U.S. federal income taxes due (including any applicable penalties and interest) as a result of an audit by the IRS. Under the new rules, unless we are eligible to (and do) elect to issue adjusted Schedules K-1 to our unitholders with respect to an audited and adjusted return, the IRS will assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to make payments of taxes, penalties, and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be

32 |

Risk Factors

substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

Treatment of distributions on the Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of the Preferred Units than the holders of our common units.

The tax treatment of distributions on the Preferred Units is uncertain. We will treat the holders of the Preferred Units as partners for tax purposes and will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of the Preferred Units as ordinary income. Although a holder of the Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually or quarterly, as provided. The holders of the Preferred Units are generally not anticipated to share in the partnership’s items of income, gain, loss or deduction, except to the extent necessary to provide, to the extent possible, the Preferred Units with the benefit of the liquidation preference.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our pipeline systems, trucking operations, terminals, processing facilities and other important physical properties are described in the segment discussions in Item 1. The facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. We believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. We are the lessee or sub-lessee under a number of cancellable and non-cancellable operating leases for certain properties including land, terminals, right-of-way permits and other operating facilities used in the terminalling, transporting, gathering and storing of crude oil, natural gas, refined products and asphalt. See “Contractual Obligations” in Item 7 and Note 10 to our consolidated financial statements in Item 8 for additional information on future commitments related to our properties.

Item 3. 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. Large, and sometimes unspecified, damages or penalties may be sought from us in some matters and certain matters may require years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of any current matter would not have a material impact on our liquidity, financial position, or results of operations.

Item 4. Mine Safety Disclosures

Not applicable.

December 31, 2018 |33

Market for Equity, Stockholder Matters and Purchases of Equity Securities

Part II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our common units trade on the NYSE under the symbol “ANDX”. As of February 21, 2019, Marathon owned 156,173,128 of our common units which constitutes a 64% ownership interest in us, and 80,000 TexNew Mex Units. The public held 89,378,204 of our outstanding common units including common units held on behalf of others as of February 21, 2019. Our common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in our partnership agreement. There were seven holders of record of our common units as of February 21, 2019.

Distribution of Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date. Available cash is defined in our partnership agreement and generally means, for any quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

At the effective time of the WNRL Merger, the IDRs were canceled (the “IDR Exchange”) as part of the general partner interests in Andeavor Logistics held by TLGP and were converted into a non-economic general partner interest in Andeavor Logistics (together with the IDR Exchange, the “IDR/GP Transaction”) in exchange for the issuance to TLGP of 78,000,000 common units. We will distribute all of our available cash with respect to any quarter (subject to the preferential distributions, if any, on the Preferred Units, as described below, and TexNew Mex Units) to our common unitholders, pro rata, as of the applicable record date.

Cash distributions will not be characterized as from operating surplus or capital surplus. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

Preferred Units

On December 1, 2017, we issued and sold 600,000 of the Preferred Units. Distributions on the Preferred Units will accrue and be cumulative from the original issue date of the Preferred Units and will be payable semi-annually in arrears on the 15th day of February and August of each year through and including February 15, 2023. After February 15, 2023, the distribution will be made quarterly in arrears on the 15th day of February, May, August, and November of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date. A prorated initial distribution on the Preferred Units was paid on February 15, 2018 in an amount equal to $14.132 per Preferred Unit.

We will not declare or pay or set aside for payment full distributions on the Preferred Units for any distribution period unless full cumulative distributions have been paid on the Preferred Units through the most recently completed distribution period for each such security. To the extent distributions will not be paid in full on the Preferred Units, TLGP will take appropriate action to ensure that all distributions declared and paid upon the Preferred Units will be reduced, declared and paid on a pro rata basis on their respective payment dates.

TexNew Mex Units

At the effective time of the WNRL Merger, each WNRL TexNew Mex Unit was automatically converted into a right to receive TexNew Mex Units, which has substantially equivalent rights and obligations as the WNRL TexNew Mex Unit.

Prior to any distributions of available cash to holders of common units, available cash with respect to any quarter will first be distributed to the holders of the TexNew Mex Units, pro rata, as of the record date, in an amount equal to 80% of the excess, if any, of (1) the TexNew Mex Shared Segment Distributable Cash Flow with respect to the applicable quarter over (2) the TexNew Mex Base Amount with respect to such quarter, less any amounts reserved with the consent of holders of a majority of the TexNew Mex Units in accordance with the Andeavor Logistics Partnership Agreement. No distributions to TexNew Mex unitholders were declared during 2017 or 2018.

See Note 11 to our consolidated financial statements in Item 8 for additional information regarding our distributions.

34 |

Selected Financial Data

Item 6. Selected Financial Data

The following table sets forth certain selected financial data as of and for each of the five years in the period ended December 31, 2018, which is derived from the combined financial results of the Predecessors, for accounting purposes and the consolidated financial results of Andeavor Logistics. Unless the context otherwise requires, references in this report to “Predecessors” refer collectively to the acquired assets from our Sponsor, and those assets, liabilities and results of operations.

In 2018, 2017 and 2016, we entered into various transactions with our Sponsor and our general partner, TLGP, pursuant to which Andeavor Logistics acquired from our Sponsor the following:

• gathering, storage and transportation assets in the Permian Basin; legacy Western Refining assets and associated crude terminals; the majority of Andeavor’s remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC on August 6, 2018. In addition, the Conan Crude Oil Gathering System and LARIP were transferred at cost plus incurred interest;

• crude oil, feedstock and refined products storage, the Anacortes marine terminal, a manifest rail facility and crude oil and refined products pipelines located in Anacortes, Washington on November 8, 2017 (the “Anacortes Logistics Assets”);

• logistic assets owned by WNRL, which consisted of pipelines, gathering, terminalling, storage, transportation and wholesale fuel distribution assets, and provides services to our Sponsor’s refining segment effective October 30, 2017;

• tankage, refined product storage, marine terminal terminalling and storage assets, pipelines, causeway and ancillary equipment located in Martinez, California, effective November 21, 2016; and

• all of the limited liability company interests in Tesoro Alaska Terminals, LLC, tankage, bulk tank farm, a truck rack and rail-loading facility, terminalling and other storage assets located in Kenai, Anchorage and Fairbanks, Alaska, completed in two stages on July 1, 2016 and September 16, 2016.

These transactions are collectively referred to as “Acquisitions from our Sponsor”. These transactions were transfers between entities under common control. Accordingly, the financial information contained herein of Andeavor Logistics have been retrospectively adjusted to include the historical results of the Predecessors to the period that the assets were initially acquired by our Sponsor. While the acquisition of the Anacortes Logistics Assets was a common control transaction, prior periods were not retrospectively adjusted as these assets did not constitute a business in accordance with ASU 2017-01, “Clarifying the Definition of a Business”. Other than WNRL and certain assets acquired in the 2018 Drop Down, our Predecessors did not record revenue for transactions with our Sponsor. For additional information regarding these adjustments, see “Business Strategy and Overview” and “Results of Operations” in Item 7.

December 31, 2018 |35

Selected Financial Data

The following table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our consolidated financial statements in Item 8.

Selected Financial Data

	Year Ended December 31,
	2018 (a)		2017 (a)		2016 (a)		2015 (a)			2014 (a)
	(In millions, except units and per unit amounts)
Statement of Operations Data
Total revenues (a) (b)	$	2,380	$	3,249	$	1,669	$	1,112		$	600
Net earnings	600		306		277		249			56
Loss attributable to Predecessors	28		43		62		43			46
Net earnings attributable to noncontrolling interest	—		—		—		(20		)	(3		)
Net earnings attributable to partners	628		349		339		272			99
Preferred unitholders’ interest in net earnings	44		3		—		—			—
General partner’s interest in net earnings, including incentive distribution rights	—		79		152		73			43
Limited partners’ interest in net earnings	584		267		187		199			43
Subordinated unitholders’ interest in net earnings	—		—		—		—			13
Net earnings per limited partner unit:
Common - basic	$	2.57	$	2.11	$	1.87	$	2.33		$	0.96
Common - diluted	2.57		2.11		1.87		2.33			0.96
Subordinated - basic and diluted	—		—		—		—			0.62
Cash distribution per unit	4.0750		3.8062		3.3070		2.8350			2.4125
	As of December 31,
	2018		2017 (a)		2016 (a)		2015 (a)			2014 (a)
	(in millions)
Balance Sheet Data
Total assets	$	10,295	$	9,505	$	6,589	$	5,131		$	4,955
Total debt, net of unamortized issuance costs	4,964		4,128		4,054		2,844			2,544

(a) Includes the historical results related to Andeavor Logistics and Predecessors. For the years ended 2015 and 2014, retrospectively adjusted amounts for the 2018 Drop Down are not shown because management does not believe presentation of these impacts is material to an investor’s understanding of Andeavor Logistics’ current operations. Other than certain assets included in the 2018 Drop Down, WNRL and transportation regulated by the FERC and the Regulatory Commission of Alaska tariffs charged to our Sponsor on the refined products pipeline included in the logistics assets acquired in 2014, our Predecessors did not record revenue for transactions with our Sponsor for assets acquired in the Acquisitions from our Sponsor prior to the effective date of each acquisition.

(b) Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for the year ended December 31, 2018 were netted. See Note 1 to our consolidated financial statements in Item 8 for further discussion.

36 |

Management’s Discussion and Analysis

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, references in this report to “Andeavor Logistics,” “the Partnership,” “we,” “us,” “our,” or “ours” refer to Andeavor 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 “Sponsor” refer collectively to Andeavor and any of Andeavor’s subsidiaries for all activity through September 30, 2018, or Marathon and any of Marathon’s subsidiaries including Andeavor LLC, successor-by-merger to Andeavor effective October 1, 2018 and a wholly owned subsidiary of Marathon, as applicable, other than Andeavor Logistics, its subsidiaries and its general partner. References in this report to “Marathon” or “MPC” refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries, including Andeavor LLC, or all of them taken as a whole.

Management’s Discussion and Analysis is our analysis of our financial performance, financial condition and significant trends that may affect future performance. All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Important Information Regarding Forward-Looking Statements” and “Risk Factors” for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business description, results of operations and financial condition should be read in conjunction with Items 1 and 2, and our consolidated financial statements and the notes thereto in Item 8.

Business Strategy and Overview

We are committed to growing our fee-based revenue and diversifying our portfolio and being a leading full-service logistics company. In recent years, we have made organic and strategic investments to transform the composition of our portfolio. Refer to Item 1 for further discussion on our segments and the assets associated with our segments’ operations. See our Capital Expenditures discussion within the Capital Resources and Liquidity section for more on our organic growth strategy.

Marathon has previously announced that it is evaluating our financial business plans with the intent to move toward financial policies that are more consistent with the approach Marathon uses for its other controlled master limited partnership, MPLX. Marathon announced that this approach includes meaningfully higher distribution coverage, leverage levels at or below 4.0x EBITDA, no planned public equity issuances and independent sustainability with limited parent support. Marathon has also previously disclosed that it is assessing strategic options for us and MPLX, which could include MPLX acquiring us or the Partnership acquiring MPLX.

Strategy and Goals

Our primary business objectives are to maintain and grow 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:

Growing a stable business that provides a competitive, full-service logistics offering to customers
Optimizing Existing Asset Base	●    Operating an incident free workplace ●    Improving operational efficiency and maximizing asset utilization ●    Expanding third-party business; delivering extraordinary customer service
Pursuing Organic Expansion Opportunities	●    Identifying and executing low-risk, high-return growth projects ●    Investing to capture the full commercial value of logistics assets ●    Growing asset capability to support Marathon value chain optimization
Growing through Third-Party Acquisitions	●    Pursuing assets and businesses in strategic U.S. geographies that support an integrated business model, delivering synergies and growth ●    Focusing on high quality assets that provide stable, fee-based income and enhancing organizational capacity
Growing through Strategic Expansion	●    Strategically partnering with Marathon on organic opportunities and acquisitions

December 31, 2018 |37

Management’s Discussion and Analysis

Relative to these goals, in 2019, we intend to continue implementing this strategy and have completed or announced plans to expand our Terminalling and Transportation business across the western and inland U.S. through:

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

• optimizing volumes and growing third-party throughput at our Terminalling and Transportation assets; and

• pursuing strategic assets in the western and inland U.S.

In addition, we have completed or announced plans to grow our assets in our Gathering and Processing segment in support of third-party demand for crude oil, natural gas and water gathering services and natural gas processing services, as well as serving Marathon’s demand for Bakken crude oil in the inland and west coast refining systems and providing crude oil supply to support Marathon’s southwest refining system through our Permian Basin logistics assets, including:

• further expanding capacity and capabilities as well as adding new origin and destination points for our common carrier pipelines in North Dakota and Montana;

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

• expanding our crude oil gathering footprint in the Permian Basin; and

• pursuing strategic assets across the western and inland U.S.

Acquisitions

2018 Drop Down

On August 6, 2018, we completed the 2018 Drop Down for total consideration of $1.55 billion. These assets include gathering, storage and transportation assets in the Permian Basin; legacy Western Refining, Inc. assets and associated crude terminals; the majority of Andeavor’s remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC. In addition, the Conan Crude Oil Gathering System and LARIP were transferred at cost plus incurred interest. The transaction was funded in part by issuing common units to Andeavor with the remainder funded with borrowings under our Dropdown Credit Facility. See further discussion of the 2018 Drop Down in Note 2 to our consolidated financial statements in Item 8.

SLC Core Pipeline System

On May 1, 2018, we completed our acquisition of the SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System) from Plains All American Pipeline, L.P. for total consideration of $180 million. The system consists of pipelines that transport crude oil to another third party pipeline system that supply the Salt Lake City area refineries, including Andeavor’s Salt Lake City refinery. We financed the acquisition using our Revolving Credit Facility. This acquisition is not material to our consolidated financial statements and its operating results are reported in our Terminalling and Transportation segment.

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 Andeavor Logistics. The financial statements of our Predecessors were prepared from the separate records maintained by Andeavor and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. 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 future performance.

How We Evaluate Our Operations

Financial and Operating Measures

Our management uses a variety of financial and operating measures to analyze operating segment performance. These measures are significant factors in assessing our operating results and profitability and include: (1) throughput volumes (including gathering pipeline and pipeline transportation, trucking, terminalling, and processing), (2) operating expenses and (3) certain other financial measures as discussed further in “Non-GAAP Financial Measures” below, including EBITDA, Segment EBITDA, Distributable Cash Flow and Distributable Cash Flow Attributable to Common Unitholders.

Management utilizes the following operating metrics to evaluate performance and compare profitability to other companies in the industry (amounts may not recalculate due to rounding of dollar and volume information):

• Average terminalling revenue per barrel;

• Average pipeline transportation revenue per barrel;

• Average margin on NGL sales per barrel;

• Average gas gathering and processing revenue per MMBtu;

38 |

Management’s Discussion and Analysis

• Average crude oil and water gathering revenue per barrel;

• Wholesale fuel sales per gallon; and

• Average wholesale fuel sales margin per gallon.

There are a variety of ways to calculate average revenue per barrel, average margin per barrel, average revenue per MMBtu, sales per gallon and average margin per gallon; other companies may calculate these in different ways.

Throughput Volumes

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas, NGLs and refined products that we handle with our pipeline, trucking, terminalling and processing assets and the volume of fuel gallons sold on our commercial wholesale contracts. These volumes are affected by the supply of, and demand for, crude oil, natural gas, NGLs and refined products in the markets served directly or indirectly by our assets. Although our Sponsor and other third-party customers have committed to minimum volumes under commercial agreements, our results of operations will be impacted by our ability to:

• increase throughput volumes on our gathering systems by making connections to new wells and to existing or new third-party pipelines or rail loading facilities, which will be driven by the anticipated supply of and demand for additional crude oil produced in the regions we operate;

• increase throughput volumes at our refined products terminals and provide additional ancillary services at those terminals, such as ethanol blending and additive injection;

• increase throughput volumes on our natural gas system through the connection of new wells and addition of compression to existing wells; and

• identify and execute organic expansion projects, and capture incremental Marathon or third-party volumes.

Additionally, increased throughput may depend on Marathon transferring volumes that it currently distributes through competing terminals to our terminals, including certain terminals located in Washington and California.

Operating Expenses

We manage our operating expenses in tandem with meeting our environmental and safety requirements and objectives and maintaining the integrity of our assets. Our operating expenses are comprised primarily of labor expenses, repairs and other maintenance costs, lease costs and utility costs. With the exception of contract labor for trucking, additive costs at our terminals and utilities, transportation and fractionation fees, which vary based on throughput volume, our expenses generally remain 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 those expenses. We seek to manage our maintenance expenditures on our pipelines and terminals by scheduling maintenance throughout the year, when possible, to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flows.

Prior to the adoption of ASC 606, our operating expenses were affected by the imbalance gain and loss provisions in our active published tariffs and in our commercial agreements with our Sponsor. As discussed further in Note 1 of Item 8, ASC 606 accounts for these effects within revenue. Under our contractual agreements or tariffs, we retain a portion of the crude oil shipped on certain of our pipelines or refined products we handle at certain of our terminals and bear any volume losses in excess of that retained amount. The value of any crude oil or refined product imbalance settlements resulting from these tariffs or contractual provisions is determined by using the average market prices for the applicable commodity, less a discount as specified in the agreement or tariff. Any settlements under tariffs or contractual provisions where we bear any crude oil or refined product volume losses are recognized in the period in which they are realized. For other terminals, and under our other commercial agreements with Andeavor, we have no obligation to measure volume losses and have no liability for physical losses.

Items Impacting Comparability

Our future results of operations may not be comparable to the historical results of operations of the acquired assets from our Predecessors for the reasons described below.

Our financial information includes the historical results of our Predecessors and the results of Andeavor Logistics for all periods presented. The financial statements of our Predecessors have been prepared from the separate records maintained by our Sponsor and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity.

There are differences in the way our Predecessors recorded revenues and the way the Partnership records revenues after the Acquisitions from our Sponsor. The assets that we acquired from our Sponsor have historically been a part of the integrated operations of our Sponsor, and, other than WNRL and certain assets acquired from the 2018 Drop Down, our Predecessors generally recognized only the costs and did not record revenue for transactions with our Sponsor. Accordingly, the revenues in our Predecessors’ historical combined financial statements relate only to amounts received from third parties for these services.

December 31, 2018 |39

Management’s Discussion and Analysis

As previously mentioned, on August 6, 2018, we completed the 2018 Drop Down for total consideration of $1.55 billion. As an entity under common control with Andeavor, we accounted for the transfers of businesses as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying results of operations have been retrospectively adjusted to include the historical results of the assets acquired prior to the effective date of the acquisition.

On June 1, 2017, pursuant to the Agreement and Plan of Merger, dated as of November 16, 2016, by and among Western Refining, Andeavor, Andeavor’s wholly-owned subsidiaries Tahoe Merger Sub 1, Inc. and Tahoe Merger Sub 2, LLC, Tahoe Merger Sub 1 was merged with and into Western Refining, with Western Refining surviving such merger as a wholly-owned subsidiary of Andeavor (the “WNR Merger”). As a result of the WNR Merger, Andeavor obtained Western Refining’s controlling interest in WNRL. Thus, the WNRL Merger was treated as a transaction of entities under common control and these consolidated financial statements reflect the operations, financial position and cash flows associated with WNRL and their related subsidiaries for the period from June 1, 2017 to December 31, 2018.

On January 1, 2018, we adopted ASC 606 utilizing the modified retrospective method. The current period results and balances are presented in accordance with ASC 606 while comparative periods continue to be presented in accordance with the accounting standards in effect for those periods. Refer to Note 1 and Note 13 within our consolidated financial statements in Item 8 for further details regarding ASC 606 and the financial impact due to adoption of the standard.

On May 1, 2018, we completed our acquisition of the SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System) from Plains All American Pipeline, L.P. for total consideration of $180 million.

Non-GAAP Measures

As a supplement to our financial information presented in accordance with U.S. GAAP, our management uses certain “non-GAAP” measures to analyze our results of operations, assess internal performance against budgeted and forecasted amounts and evaluate future impacts to our financial performance as a result of capital investments, acquisitions, divestitures and other strategic projects. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings, operating income and net cash from operating activities. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures. These non-GAAP measures are defined in our glossary of terms. These measures may be used to assess our operating results and profitability and include:

• Financial non-GAAP measure of EBITDA;

• Financial non-GAAP measure of distributable cash flow;

• Financial non-GAAP measure of Segment EBITDA;

• Liquidity non-GAAP measure of distributable cash flow;

• Liquidity non-GAAP measure of distributable cash flow attributable to common unitholders;

• Operating performance measure of average margin on NGL sales per barrel; and

• Operating performance measure of average wholesale fuel sales margin per gallon.

We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results, including but not limited to:

• 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.

For further information regarding these non-GAAP measures including the reconciliation of these non-GAAP measures to their most directly comparable U.S. GAAP financial measures, see the “Non-GAAP Reconciliations” section.

40 |

Management’s Discussion and Analysis

Consolidated Results

Highlights (in millions)

(a) Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for year ended December 31, 2018 were netted. See Note 1 to our consolidated financial statements in Item 8 for further discussion.

(b) See “Non-GAAP Reconciliations” section below for further information regarding these non-GAAP measures.

Percentage of Segment Operating Income by Operating Segment

December 31, 2018 |41

Management’s Discussion and Analysis

2018 Versus 2017

Net Earnings Reconciliation (in millions)

Overview

Our net earnings for 2018increased$294 million, or 96%, to $600 million from $306 million for 2017 and EBITDA increased$252 million primarily driven by a full year of contributions from the WNRL Merger and the Anacortes Logistics Assets, the 2018 Drop Down and the SLC Core Pipeline System acquisition. Partially offsetting those contributions were increases in operating costs and depreciation and amortization expenses related to the WNRL Merger and 2018 acquisitions.

Segment Results

Operating income increased$193 million to $796 million during 2018 compared to $603 million for 2017 driven by a full year of contributions from the WNRL Merger during 2018 across all our segments, the 2018 Drop Down, the SLC Core Pipeline System acquisition and a full year of contributions from our acquisition of the Anacortes Logistics Assets. Refer to our detailed discussion of each segment’s operating and financial results contained in this section.

Revenues

Revenues for 2018decreased$869 million, or 27%, to $2.4 billion, driven by the impacts of the adoption of ASC 606 on January 1, 2018, partially offset by a full year of operations from the WNRL Merger and Anacortes Logistics Assets as well as the 2018 Drop Down and the SLC Core Pipeline System acquisition during 2018.

Cost of Fuel and Other

Due to the adoption of ASC 606 on January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements within our Wholesale segment were netted for 2018, as noted above and further described in Note 13 to our consolidated financial statements in Item 8.

NGL Expense

NGL expense decreased$59 million primarily due to the impact from the adoption of ASC 606 on January 1, 2018, partially offset by an increase in expenses for the Robinson Lake and Belfield facilities driven by higher production during 2018. Refer to Note 13 to our consolidated financial statements in Item 8 for further information regarding the adoption of ASC 606.

Operating Expenses

Operating expenses increased$194 million primarily due to a full year of operations from the WNRL Merger and the 2018 Drop Down as well as the recognition of non-cash expenses in connection with the adoption of ASC 606.

(Gain) Loss on Asset Disposals and Impairments

The gain on asset disposals of $25 million during 2017 was due to the sale of a products terminal in Alaska. 2018 had minor losses in connection with routine disposals.

Interest and Financing Costs, Net

Net interest and financing costs decreased$97 million primarily due to lower interest rates from the refinancing of debt with new senior notes during the fourth quarter of 2017 reflecting our improved investment grade credit rating.

Equity in Earnings of Equity Method Investments

The increase of $9 million in earnings of equity method investments was due to earnings from ALRP, which was acquired in January 2018, and a full year of MPL, which was acquired in June 2017.

42 |

Management’s Discussion and Analysis

2017 Versus 2016

Net Earnings Reconciliation (in millions)

Overview

Our net earnings for 2017increased$29 million, or 10%, to $306 million from $277 million for 2016 primarily driven by the North Dakota Gathering and Processing Assets acquisition and increased contributions from the Acquisitions from our Sponsor during the second half of 2016 and 2017. Partially offsetting those contributions were transaction costs in connection with our acquisitions and interest and financing costs associated with our new senior notes issuances. EBITDA increased$244 million reflecting the impact of the Acquisitions from our Sponsor, the North Dakota Gathering and Processing Assets acquisition in January 2017 and organic growth in the pipeline and terminalling assets.

The revenue and costs of sales associated with the POP arrangements we acquired in the North Dakota Gathering and Processing Assets acquisition are reported gross on our financial statements. Furthermore, as part of the WNRL Merger, we acquired a wholesale fuels business. During 2017 and 2016, the revenue and related cost of fuels were reported gross on our financial statements. Both of these revenue streams contributed to our higher revenue and operating costs.

Segment Results

Operating income increased$155 million to $603 million during 2017 compared to $448 million for 2016 driven by contributions from the Acquisitions from our Sponsor across all of our segments. Refer to our detailed discussion of each segment’s operating and financial results contained in this section.

Revenues

Revenues for 2017increased$1.6 billion, or 95%, to $3.2 billion, driven by the WNRL Merger, the North Dakota Gathering and Processing Assets, the acquisitions of certain terminalling and storage assets in Alaska (the “Alaska Storage and Terminalling Assets”) and Northern California (the “Northern California Terminalling and Storage Assets”) from our Sponsor in the second half of 2016.

Cost of Fuel and Other and NGL Expense

Cost of fuel and other and NGL expense for 2017 increased $1.2 billion from 2016 due to the WNRL Merger and North Dakota Gathering and Processing Assets, respectively.

Operating Expenses

Operating expenses increased$131 million primarily due to the WNRL Merger, the North Dakota Gathering and Processing Assets and an environmental accrual related to the expected final remediation for the 2013 crude oil pipeline release at Tioga, North Dakota.

(Gain) Loss on Asset Disposals and Impairments

The gain on asset disposals during 2017 of $25 million was due to the sale of a products terminal in Alaska. 2016 had minor losses in connection with routine disposals.

Interest and Financing Costs, Net

Net interest and financing costs increased$135 million primarily related to transactional costs of new senior notes during 2017 that included $60 million in early redemption premiums and $17 million in write-offs of unamortized issuance costs. Also contributing to the increase was a full-year of interest from our senior notes issued during 2016 as well as the interest related to WNRL’s outstanding debt.

December 31, 2018 |43

Management’s Discussion and Analysis

Terminalling and Transportation

Refer to Item 1 for a description of our Terminalling and Transportation segment operations.

Highlights (in millions)

(a) See “Non-GAAP Reconciliations” section below for further information regarding this non-GAAP measure.

Terminalling and Transportation Segment Operating Data

(a) Adjusted to include the historical results of the Predecessors.

Volumes

Terminalling throughput increased307 Mbpd, or 21%, in 2018 compared to 2017 primarily as a result of a full year of operations from the WNRL Merger, the 2018 Drop Down and the SLC Core Pipeline System acquisition. Pipeline transportation throughput volume increased110 Mbpd, or 12%, in 2018 compared to 2017, which was primarily attributable to continued strong product demand as well as contributions from the Anacortes Logistics Assets and the SLC Core Pipeline System acquisition.

Terminalling throughput increased448 Mbpd, or 45%, in 2017 compared to 2016 primarily as a result of the WNRL Merger, an increase in marine volumes in Southern California and other contributions from assets acquired from our Sponsor, in particular, marine volumes from the Avon marine terminal assets from the Northern California Terminalling and Storage Assets acquisition and contributions from the operations from the Alaska Storage and Terminalling Assets acquisition. Pipeline transportation throughput increased34 Mbpd, or 4%, in 2017 compared to 2016, which was primarily attributable to an increase in pipeline volumes in Southern California from strong refinery utilization.

44 |

Management’s Discussion and Analysis

Terminalling and Transportation Segment Operating Results (in millions, except per barrel amounts)

	Year Ended December 31,
	2018 (a)		2017 (a)			2016 (a)
Revenues
Terminalling	$	888	$	690		$	480
Pipeline transportation	160		130			125
Other revenues	6		18			—
Total Revenues	1,054		838			605
Costs and Expenses
Operating expenses (excluding depreciation and amortization)	373		302			231
General and administrative expenses	38		47			38
Depreciation and amortization expenses	144		117			95
(Gain) loss on asset disposals and impairments	1		(25		)	1
Operating Income	$	498	$	397		$	240
Segment EBITDA (b)	$	660	$	530		$	335
Rates (c)
Average terminalling revenue per barrel	$	1.38	$	1.30		$	1.31
Averagepipelinetransportation revenue per barrel	$	0.43	$	0.40		$	0.39

(a) Adjusted to include the historical results of the Predecessors.

(b) See “Non-GAAP Reconciliations” section for further information regarding this non-GAAP measure.

(c) Amounts may not recalculate due to rounding of dollar and volume information.

2018 Versus 2017

Our Terminalling and Transportation segment’s operating income increased$101 million, or 25%, in 2018 compared to 2017. Segment EBITDA increased$130 million, or 25%, in 2018 compared to 2017.

Revenues increased$216 million, or 26%, to $1.1 billion in 2018 compared to $838 million in 2017 primarily attributable to a full year of operations from WNRL and the Anacortes Logistics Assets as well as the 2018 Drop Down and other organic growth.

Operating expenses increased$71 million, or 24%, to $373 million in 2018 compared to $302 million in 2017 due to acquisitions.

Depreciation and amortization expenses increased$27 million, or 23%, to $144 million in 2018 compared to $117 million in 2017 due to acquisitions.

The gain on asset disposals during 2017 was due to the sale of a products terminal in Alaska.

2017 Versus 2016

Our Terminalling and Transportation segment’s operating income increased$157 million, or 65%, in 2017 compared to 2016. Segment EBITDA increased$195 million, or 58%, in 2017 compared to 2016.

Revenues increased$233 million, or 39%, to $838 million in 2017 compared to $605 million in 2016 primarily attributable to revenues associated with the Northern California Terminalling and Storage Assets, the Alaska Storage and Terminalling Assets acquisitions in the second half of 2016, and the WNRL operations acquired in June 2017. Also contributing to the increase in revenues was higher marine terminalling revenues in California driven by higher refinery utilization.

Operating expenses increased$71 million, or 31%, to $302 million in 2017 compared to $231 million in 2016 due to acquisitions.

Depreciation and amortization expenses increased$22 million, or 23%, to $117 million in 2017 compared to $95 million in 2016 due to acquisitions.

The gain on asset disposals during 2017 was due to the sale of a products terminal in Alaska.

December 31, 2018 |45

Management’s Discussion and Analysis

Gathering and Processing

Refer to Item 1 for a description of our Gathering and Processing segment operations.

Highlights (in millions)

(a) See “Non-GAAP Reconciliations” section below for further information regarding this non-GAAP measure.

Gathering and Processing Segment Operating Data

(a) Volumes represent barrels sold in keep-whole arrangements, net barrels retained in POP arrangements and other associated products.

(b) The adoption of ASC 606 changed the presentation of our gas gathering and processing throughput volumes. Volumes processed internally to enhance our NGL sales are no longer reported in our throughput volumes as certain fees contained within our commodity contracts are now reported as a reduction of “NGL expense.” The impact of the adoption in 2018 was 176 thousand MMBtu/d now being used internally and not reported in the throughput volumes used to calculate our average gas gathering and processing revenue per MMBtu.

(c) Adjusted to include the historical results of the Predecessors.

Volumes

NGL sales volume increased2.1 Mbpd, or 25%, in 2018 compared to 2017 primarily due to ethane recovery in the Rockies Region in 2018. Ethane recovery is the process of capturing ethane during the NGL processing stream, where it is then fractionated and sold. Gas gathering and processing throughput volumes decreased200 thousand MMBtu/d, or 21%, in 2018. This decrease was primarily driven by the adoption of ASC 606, which changed the presentation of certain of our volumes. The impact of the adoption is described further in Note 13 to our consolidated financial statements in Item 8 for additional information. Planned downtime at our Robinson Lake gas processing facility also resulted in lower volumes during 2018. Crude oil and water gathering volumes increased65 Mbpd, or 17%, during 2018 as a result of a full year of contributions from the WNRL Merger and the 2018 Drop Down.

NGL sales volume increased0.8 Mbpd, or 11%, in 2017 compared to 2016 primarily due an increase related to the equity NGLs associated with the acquired North Dakota Gathering and Processing Assets, partially offset by keep-whole decreases in the Rockies Region. Gas gathering and processing throughput volumes increased84 thousand MMBtu/d in 2017 compared to 2016, driven primarily by the North Dakota Gathering and Processing Assets acquired providing more volumes on our systems. Crude oil and water gathering volumes increased108 Mbpd, or 39%, in 2017, as a result of projects to expand the pipeline gathering system capabilities, which included additional origin and destination inter-connections, the North Dakota Gathering and Processing Assets and the WNRL assets acquired. This was partially offset by decreased volumes related to the turnaround completed on Marathon’s Mandan refinery, which impacted volumes as well as the average crude oil and water revenue per barrel due to shorter pipeline haul movements.

46 |

Management’s Discussion and Analysis

Gathering and Processing Segment Results (in millions, except per barrel and per MMBtu amounts)

	Year Ended December 31,
	2018 (a)		2017 (a)		2016 (a)
Revenues
NGL sales (b)	$	436	$	369	$	103
Gas gathering and processing	330		333		264
Crude oil and water gathering (f)	336		262		582
Pass-thru and other (c)	161		165		115
Total Revenues	1,263		1,129		1,064
Costs and Expenses
Cost of fuel and other (excluding items shown separately below) (f)	—		—		316
NGL expense (excluding items shown separately below) (b)(c)	206		265		2
Operating expenses (excluding depreciation and amortization)	489		374		329
General and administrative expenses	42		54		41
Depreciation and amortization expenses	213		191		138
Loss on asset disposals and impairments	3		—		3
Operating Income	$	310	$	245	$	235
Segment EBITDA (d)	$	537	$	446	$	392
Rates (e)
Average margin on NGL sales per barrel (b)(c)(d)	$	59.92	$	34.77	$	36.59
Average gas gathering and processing revenue per MMBtu	$	1.19	$	0.95	$	0.82
Average crude oil and water gathering revenue per barrel (f)	$	2.05	$	1.86	$	5.76

(a) Adjusted to include the historical results of the Predecessors.

(b) We had 24.4 Mbpd and 22.2 Mbpd of gross NGL sales under POP and keep-whole arrangements for the years ended December 31, 2018 and 2017, respectively. We retained 10.4 Mbpd and 8.3 Mbpd, respectively, under these arrangements. The difference between gross sales barrels and barrels retained is reflected in NGL expense resulting from the gross presentation required for the POP arrangements associated with the North Dakota Gathering and Processing Assets.

(c) Included in NGL expense for 2017 were $2 million of costs related to crude oil volumes obtained in connection with the North Dakota Gathering and Processing Assets acquisition. The corresponding revenues were recognized in pass-thru and other revenue. As such, the calculation of the average margin on NGL sales per barrel excludes this amount.

(d) See “Non-GAAP Reconciliations” section for further information regarding this non-GAAP measure.

(e) Amounts may not recalculate due to rounding of dollar and volume information.

(f) The retrospectively adjusted results for the year ended December 31, 2016 included certain contracts of our Predecessor that were recognized as buy/sell arrangements. There were no such arrangements during the years ended December 31, 2018 or 2017.

2018 Versus 2017

Our Gathering and Processing segment’s operating income increased$65 million, or 27%, in 2018 compared to 2017. Segment EBITDA increased$91 million, or 20%, in 2018 compared to 2017.

For a portion of 2018, there was planned downtime at the Robinson Lake gas processing facility to allow for a capacity expansion project, which was successfully completed in 2018.

Revenues for our crude oil and water gathering systems improved due to the impact from a full year of operations from WNRL increasing the throughput volumes and improving our tariff mix. Revenues also increased due to continued strong volume growth in our Permian crude oil gathering assets during 2018 and Marathon’s Mandan refinery undergoing a turnaround in 2017. Revenues were also impacted by the adoption of ASC 606, as further described in Note 13 in Item 8. Certain cost recoveries previously presented as service revenues in Pass-thru and other revenues are now reflected as reductions to NGL expense, resulting in an increase to the average margin on NGL sales per barrel, but had an immaterial impact on our segment operating income and Segment EBITDA.

In addition, we had incremental operating expenses and depreciation expenses primarily associated with the WNRL Merger and the adoption of ASC 606, as further described in Note 13.

2017 Versus 2016

Our Gathering and Processing segment’s operating income increased$10 million, or 4%, in 2017 compared to 2016. Segment EBITDA increased$54 million, or 14%, in 2017 compared to 2016.

The North Dakota Gathering and Processing Assets added margin of $12 million associated with the sale of NGLs. Revenues increased across our natural gas gathering and processing systems and our crude oil and water gathering systems with this acquisition, Predecessor contributions from the 2018 Drop Down and expanded capabilities on existing assets along with the addition of WNRL operations. Offsetting the incremental margin was a decline in revenues resulting from lower volumes in the Rockies Region and incremental administrative, operating and depreciation expenses primarily associated with the North Dakota Gathering and Processing Assets and WNRL operations acquired, partially offset by contributions from the 2018 Drop Down in 2016.

December 31, 2018 |47

Management’s Discussion and Analysis

Wholesale

Refer to Item 1 for a description of our Wholesale segment operations.

Highlights (in millions)

(a) See “Non-GAAP Reconciliations” section below for further information regarding this non-GAAP measure.

Wholesale Segment Operating Results and Data (in millions, except per gallon amounts)

	Year Ended December 31,
	2018			2017 (a)
Revenues
Fuel sales (b)	$	46		$	1,267
Other wholesale	33			15
Total Revenues	79			1,282
Costs and Expenses
Cost of fuel and other (excluding items shown separately below) (b)	—			1,244
Operating expenses (excluding depreciation and amortization)	39			15
General and administrative expenses	2			3
Depreciation and amortization expenses	11			5
Operating Income	$	27		$	15
Segment EBITDA (c)	$	38		$	20
Rates (d)
Wholesale fuel sales per gallon (b)		3.8	¢
Average wholesale fuel sales margin per gallon (b)(c)					3.0	¢

Financial Results

The Wholesale segment’s operating income was $27 million and $15 million and Segment EBITDA was $38 million and $20 million for the years ended December 31, 2018 and 2017, respectively. Results for the year ended 2018 compared to the year ended 2017 were due to only seven months of activity reported for the Wholesale segment for the year ended 2017, seasonally higher volumes and an improved wholesale margin environment.

Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for 2018 were netted. Therefore, we no longer present cost of fuel and other or average margin on fuel sales per gallon. Instead, we now present wholesale fuel sales per gallon, which is not a direct comparison of the previous metric. The impact of the adoption is described further in Note 1 and Note 13 in Item 8.

Volumes

Fuel sales volumes increased 496 million gallons in 2018 as compared to 2017 primarily due to only seven months of activity reported for the Wholesale segment for the year ended 2017.

(a) Adjusted to include the historical results of the Predecessors. The 2017 period only includes the results beginning June 1, 2017.

(b) Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for the year ended 2018 were netted. Therefore, we no longer present cost of fuel and other or average margin on fuel sales per gallon. Instead, we now present wholesale fuel sales per gallon, which is not a direct comparison of the previous metric.

(c) See “Non-GAAP Reconciliations” section for further information regarding this non-GAAP measure.

(d) Amounts may not recalculate due to rounding of dollar and volume information.

48 |

Management’s Discussion and Analysis

Non-GAAP Reconciliations

Reconciliation of Net Earnings to EBITDA (in millions)

(a) Adjusted to include the historical results of the Predecessors.

Reconciliation of Segment Operating Income to Segment EBITDA (in millions)

	Year Ended December 31,
	2018 (a)		2017 (a)		2016 (a)			2018 (a)		2017 (a)		2016 (a)			2018		2017 (a)
	Terminalling and Transportation						Gathering and Processing							Wholesale
Segment Operating Income	$	498	$	397	$	240		$	310	$	245	$	235		$	27	$	15
Depreciation and amortization expenses	144		117		95			213		191		138			11		5
Equity in earnings of equity method investments	17		12		—			14		10		13			—		—
Other income, net	1		4		—			—		—		6			—		—
Segment EBITDA	$	660	$	530	$	335		$	537	$	446	$	392		$	38	$	20

(a) Adjusted to include the historical results of the Predecessors.

December 31, 2018 |49

Management’s Discussion and Analysis

Reconciliation of EBITDA to Distributable Cash Flow (in millions)

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
EBITDA	$	1,201		$	949		$	705
Predecessor impact	12			8			13
Maintenance capital expenditures (b)	(111		)	(119		)	(72		)
Reimbursement for maintenance capital expenditures (b)	33			31			28
Changes in deferred revenue (c)	3			3			7
Net (gain) loss on asset disposals and impairments	4			(25		)	4
Interest and financing costs, net	(233		)	(330		)	(195		)
Proceeds from sale of assets	—			29			8
Amortized debt costs	10			85			12
Adjustments for equity method investments	17			18			17
Other (d)	12			19			5
Distributable Cash Flow	948			668			532
Less: Preferred unit distributions (e)	(41		)	(3		)	—
Distributable Cash Flow Attributable to Common Unitholders	$	907		$	665		$	532

(a) Adjusted to include the historical results of the Predecessors.

(b) We adjust our reconciliation of distributable cash flows for maintenance capital expenditures, tank restoration costs and expenditures required to ensure the safety, reliability, integrity and regulatory compliance of our assets with an offset for any reimbursements received for such expenditures.

(c) Included in changes in deferred revenue are adjustments to remove the impact of the adoption of ASC 606 on January 1, 2018 as well as the impact from the timing of recognition with certain of our contracts that contain minimum volume commitment with clawback provisions.

(d) Other includes items that had a non-cash impact on our operations and should not be considered in distributable cash flow. Non-cash items primarily include the exclusion of the non-cash gain of $6 million recognized relating to the settlement of the Questar Gas Company litigation for the year ended December 31, 2016.

(e) Represents the cash distributions earned by the Preferred Units for the years ended December 31, 2018 and 2017 assuming a distribution is declared by the Board. Cash distributions to be paid to holders of the Preferred Units are not available to common unitholders.

Reconciliation of Net Cash from Operating Activities to Distributable Cash Flow (in millions)

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
Net Cash from Operating Activities	$	1,029		$	687		$	442
Changes in assets and liabilities	(17		)	14			104
Predecessors impact	12			8			13
Maintenance capital expenditures (b)	(111		)	(119		)	(72		)
Reimbursement for maintenance capital expenditures (b)	33			31			28
Adjustments for equity method investments	(4		)	3			2
Gain (loss) on sales of assets, net of proceeds	—			29			8
Changes in deferred revenues (c)	3			3			7
Other (d)	3			12			—
Distributable Cash Flow	948			668			532
Less: Preferred unit distributions (e)	(41		)	(3		)	—
Distributable Cash Flow Attributable to Common Unitholders	$	907		$	665		$	532

(a) Adjusted to include the historical results of the Predecessors.

(b) We adjust our reconciliation of distributable cash flows for maintenance capital expenditures, tank restoration costs and expenditures required to ensure the safety, reliability, integrity and regulatory compliance of our assets with an offset for any reimbursements received for such expenditures.

(c) Included in changes in deferred revenue are adjustments to remove the impact of the adoption of ASC 606 on January 1, 2018 as well as the impact from the timing of recognition with certain of our contracts that contain minimum volume commitment with clawback provisions.

(d) Other includes items that had a non-cash impact on our operations and should not be considered in distributable cash flow. Non-cash items primarily include the exclusion of the non-cash gain of $6 million recognized relating to the settlement of the Questar Gas Company litigation for the year ended December 31, 2016.

50 |

Management’s Discussion and Analysis

(e) Represents the cash distributions earned by the Preferred Units for the years ended December 31, 2018 and 2017 assuming a distribution is declared by the Board. Cash distributions to be paid to holders of the Preferred Units are not available to common unitholders.

Average Margin on NGL Sales per Barrel (in millions, except days, barrels and per barrel amounts)

	Year Ended December 31,
	2018			2017			2016
Gathering and Processing Segment Operating Income	$	310		$	245		$	235
Add back:
Cost of fuel and other (excluding items shown separately below)	—			—			316
Operating expenses (excluding depreciation and amortization)	489			374			329
General and administrative expenses	42			54			41
Depreciation and amortization expenses	213			191			138
Loss on asset disposals and impairments	3			—			3
Other commodity purchases (a)	—			2			—
Subtract:
Gas gathering and processing revenues	(330		)	(333		)	(264		)
Crude oil gathering revenues	(336		)	(262		)	(582		)
Pass-thru and other revenues	(161		)	(165		)	(115		)
Margin on NGL Sales	$	230		$	106		$	101
Divided by Total Volumes for the Period:
NGLs sales volumes (Mbpd)	10.4			8.3			7.5
Number of days in the period	365			365			366
Total volumes for the period (thousands of barrels) (b)	3,796			3,030			2,745
Average Margin on NGL Sales per Barrel (b)	$	59.92		$	34.77		$	36.59

(a) Included in the NGL expense for the year ended December 31, 2017 was $2 million of costs related to crude oil volumes obtained and immediately sold in connection with the North Dakota Gathering and Processing Assets acquisition.

(b) Amounts may not recalculate due to rounding of dollar and volume information.

Average Wholesale Fuel Sales Margin per Gallon (in millions, except per gallon amounts)

	Period Ended
	December 31, 2017 (a)
Wholesale Segment Operating Income	$	15
Add back:
Operating expenses (excluding depreciation and amortization)	15
General and administrative expenses	3
Depreciation and amortization expenses	5
Subtract:
Other wholesale revenues	(15		)
Wholesale Fuel Sales Margin	$	23
Divided by Total Volumes for the Period:
Fuel sales volumes (millions of gallons)	722
Average Wholesale Fuel Sales Margin per Gallon (b)		3.0	¢

(a) Adjusted to include the historical results of the Predecessors. The 2017 period only includes the results beginning June 1, 2017, the date the business was originally acquired by our Sponsor.

(b) Amounts may not recalculate due to rounding of dollar and volume information.

December 31, 2018 |51

Management’s Discussion and Analysis

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 our revolving credit facilities, including the MPC Loan Agreement, and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital, long-term capital expenditure, acquisition and debt servicing requirements and allow us to fund at least the minimum quarterly cash distributions.

Equity Overview

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders’ capital accounts based on their ownership interest at the time of issuance.

Unit Issuance

In connection with the 2018 Drop Down, we issued 28,283,742 common units to our Sponsor.

In February 2017, we closed a registered public offering of 5,000,000 common units representing limited partner interests at a public offering price of $56.19 per unit. The net proceeds of $281 million were used to repay borrowings outstanding under our Revolving Credit Facility and for general partnership purposes. Also, general partner units of 101,980 were issued for proceeds of $6 million.

In connection with the WNRL Merger, we issued 15,182,996 publicly held common units and 14,853,542 common units to our Sponsor. In addition, in October 2017, we issued 78,000,000 of our common units to TLGP in connection with the IDR/GP Transaction and converted our general partner units into non-economic general partner units.

Issuance of Preferred Units

In December 2017, we issued and sold 600,000 Preferred Units, at a price to the public of $1,000 per unit. We used the net proceeds from the sale of the Preferred Units (i) to primarily redeem $500 million principal amount of our 6.250%2022 Notes,

(ii) to repay a portion of the borrowings under our Revolving Credit Facility and (iii) to pay fees and expenses associated with the foregoing.

At any time on or after February 15, 2023, we may redeem the Preferred Units, in whole or in part at a redemption price of $1,000 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions up to, but not including, the date of redemption, whether or not declared. In addition, upon the occurrence of certain rating agency events as described in the prospectus, we may redeem the Preferred Units, in whole but not in part, at a price of $1,020 per Preferred Unit, plus an amount equal to all accumulated and unpaid distributions up to, but not including, the date of redemption, whether or not declared.

Distributions on the Preferred Units will accrue and be cumulative from the original issue date of the Preferred Units and will be payable semi-annually in arrears on the 15th day of February and August of each year. If any Distribution Payment Date otherwise would fall on a day that is not a business day, declared distributions will be paid on the immediately succeeding business day without the accumulation of additional distributions.

The initial distribution rate for the Preferred Units is 6.875% per annum of the $1,000 liquidation preference per Preferred Unit (equal to $68.75 per Preferred Unit per annum). On and after February 15, 2023, distributions on the Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 4.652%.

TexNew Mex Units

At the effective time of the WNRL Merger, each WNRL TexNew Mex Unit was automatically converted into a right to receive the TexNew Mex Units, which has substantially equivalent rights and obligations as the WNRL TexNew Mex Unit.

Prior to any distributions of available cash to holders of common units, available cash with respect to any quarter will first be distributed to the holders of the TexNew Mex Units, pro rata, as of the record date, in an amount equal to 80% of the excess, if any, of (1) the TexNew Mex Shared Segment Distributable Cash Flow with respect to the applicable quarter over (2) the TexNew Mex Base Amount with respect to such quarter, less any amounts reserved with the consent of holders of a majority of the TexNew Mex Units in accordance with the Andeavor Logistics Partnership Agreement. No distributions to TexNew Mex unitholders were declared during 2018 or 2017. As of December 31, 2018, we had 80,000 TexNew Mex Units outstanding.

ATM Program

In August 2017, we filed a prospectus supplement to our shelf registration filed with the SEC in August 2015, authorizing the continuous issuance of up to an aggregate of $750 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 program referred to as our “2017 ATM Program”). During the year ended December 31, 2017, we issued an aggregate of 72,857 common units under our 2017 ATM Program, generating

52 |

Management’s Discussion and Analysis

proceeds of $3 million before issuance costs. We paid fees of less than $1 million related to the issuance of units under this program for the year ended December 31, 2017. The net proceeds from sales under the 2017 ATM Program were used for general partnership purposes, which may include debt repayment, future acquisitions, capital expenditures and additions to working capital. There were no issuances in 2018.

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 will receive. Simultaneously with the closing of the WNRL Merger: (i) the IDRs were canceled, (ii) the general partner interests in Andeavor Logistics held by TLGP were converted into a non-economic general partner interest in Andeavor Logistics, and (iii) Andeavor and its affiliates, including TLGP, agreed to increase and extend existing waivers on distributions to Andeavor and its affiliates by $60 million to an aggregate of $160 million between 2017 and 2019.

Quarterly Distributions

Quarter Ended	Total Quarterly Distribution Per Common Unit		Total Quarterly Distribution Per Common Unit, Annualized		Total Cash Distribution (in millions)		Date of Distribution
December 31, 2018	$	1.0300	$	4.12	$	238	February 14, 2019
September 30, 2018	1.0300		4.12		238		November 14, 2018
June 30, 2018	1.0300		4.12		209		August 14, 2018
March 31, 2018	1.0150		4.06		205		May 15, 2018
December 31, 2017	1.0000		4.00		205		February 14, 2018
September 30, 2017	0.9852		3.94		201		November 14, 2017
June 30, 2017 (a)	0.9710		3.88		147		August 14, 2017
March 31, 2017	0.9400		3.76		140		May 15, 2017

(a) On July 25, 2017, WNRL declared a quarterly cash distribution of $0.4675 per common unit, which was paid on August 18, 2017, in the amount of $33 million.

Debt Overview

Total Debt

	December 31,
Debt, including current maturities:	2018			2017
Revolving Credit Facility	$	945		$	423
Dropdown Credit Facility	300			—
MPC Loan Agreement	—			—
5.500% Senior Notes due 2019	500			500
3.500% Senior Notes due 2022 (a)	500			500
6.250% Senior Notes due 2022	300			300
6.375% Senior Notes due 2024	450			450
5.250% Senior Notes due 2025	750			750
4.250% Senior Notes due 2027 (a)	750			750
5.200% Senior Notes due 2047 (a)	500			500
Capital lease obligations	15			9
Total Debt	5,010			4,182
Unamortized Issuance Costs (a)	(46		)	(54		)
Debt, Net of Unamortized Issuance Costs	$	4,964		$	4,128

(a) Unamortized discounts of $4 million and $5 million associated with these senior notes are included in unamortized issuance costs at December 31, 2018 and 2017, respectively.

December 31, 2018 |53

Management’s Discussion and Analysis

Senior Notes by Maturity (in millions)

Credit Facilities

Under our current Revolving Credit Facility and Dropdown Credit Facility, we have the option to elect whether 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 weighted average interest rate for borrowings under our Revolving Credit Facility and Dropdown Credit Facility was 4.33% and 4.14%, respectively, at December 31, 2018. The Revolving Credit Facility and the Dropdown Credit Facility both mature on January 29, 2021.

Expenses and Fees of Our Credit Facilities

Credit Facility	30 day Eurodollar (LIBOR) Rate at December 31, 2018	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (a)	2.50%	1.75%	5.50%	0.75%	0.300%
Dropdown Credit Facility (a)	2.50%	1.76%	5.50%	0.76%	0.300%

(a) We have the option to elect whether the borrowings will bear interest at either a Eurodollar rate, for the applicable period, plus the Eurodollar margin, or a base rate plus the base rate margin of the borrowing. The applicable margins vary based upon our credit ratings. We also incur commitment fees for the unused portion of the Revolving Credit Facility and Dropdown Credit Facility at an annual rate. Letters of credit outstanding under the Revolving Credit Facility incur fees at the Eurodollar margin rate.

On January 5, 2018, we amended our existing secured Revolving Credit Facility to, among other things, (i) increase the aggregate commitments from $600 million to $1.1 billion, (ii) add certain financial institutions as additional lenders under the revolving credit agreement and (iii) make certain changes to the credit agreements to permit the incurrence of an additional $500 million of incremental loans under the Revolving Credit Facility and the Dropdown Credit Facility (to be shared between the credit agreements), subject to the satisfaction of certain conditions. See further discussion in Note 8 to our consolidated financial statements in Item 8.

On December 20, 2018, we amended our Revolving Credit Facility and Dropdown Credit Facility to, among other things, (i) grant additional flexibility to the Partnership and its subsidiaries to create liens and incur indebtedness, subject to the negative financial covenant that requires us to maintain a Consolidated Leverage Ratio (as defined in the credit agreements) of no greater than 5.0 to 1.0 (or 5.5 to 1.0 during the two fiscal quarters following certain acquisitions), (ii) remove restrictions on the ability of the Partnership and its subsidiaries to make investments and (iii) grant additional flexibility to the Partnership and its subsidiaries to enter into acquisitions, sell or dispose of assets and enter into related party transactions. In addition, we amended our Revolving Credit Facility and Dropdown Credit Facility to make certain legal and technical updates to the revolving credit facility agreements, including the removal of collateral and security provisions that are no longer applicable and changes to reflect the previously reported acquisition of Andeavor by MPC effective on October 1, 2018.

Loan Agreement

On December 21, 2018, we entered into the MPC Loan Agreement. Under the terms of the MPC Loan Agreement, MPC will make a loan or loans (the “Loan”) to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding exceeding

54 |

Management’s Discussion and Analysis

$500 millionat any one time. The MPC Loan Agreement matures and the entire unpaid principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, owed by the Partnership under the MPC Loan Agreement will become due and payable on December 21, 2023, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, at any time prior to the maturity date. Interest will accrue on the unpaid principal amount of the Loan at a rate equal to the sum of (i) the one-month term LIBOR for dollar deposits, plus (ii) a premium of1.75basis points (or such lower premium then applicable under the Partnership’s credit agreements). There were no borrowings under the MPC Loan Agreement during 2018.

Covenants

The credit facility agreements contain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for agreements of these types. The sole financial covenant that we are required to maintain, as of the last day of the fiscal quarter, is a Consolidated Leverage Ratio (as defined in the credit facility agreements) of no greater than 5.00 to 1.00. As of December 31, 2018, we were in compliance with this financial covenant.

Investment Grade Rating

During 2017, we achieved an investment grade rating. An investment grade rating aligns with our capital allocation and financial principles. Benefits of investment grade ratings are:

• Lower Cost of Capital - We expect to realize incremental interest savings and lower new issuance costs;

• Balance Sheet Flexibility - We have the ability to extend our maturity profile to increase duration and match asset life. This provides simplified and less restrictive covenants;

• Financial and Operational Flexibility - We gain access to improved commercial terms that reduce the need for letters of credit. This enhances our financial standing with customers, suppliers and partners; and

• Improved Market Access - We have the opportunity to a greater market depth and breadth that provides stability and reliable access. We now have access to subordinated debt and preferred equity markets.

Sources and Uses of Cash

Components of Cash Flows (in millions)

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
Cash Flows From (Used In):
Operating Activities	$	1,029		$	687		$	442
Investing Activities	(1,149		)	(1,533		)	(658		)
Financing Activities	55			233			888
Increase (Decrease) in Cash and Cash Equivalents	$	(65	)	$	(613	)	$	672

(a) Includes the historical results related to the Partnership and Predecessors.

2018 Versus 2017

Net cash from operating activities increased$342 million to $1.0 billion in 2018 from $687 million in 2017. The increase in net cash from operating activities was primarily due to an increase in net earnings after considering the impacts of non-cash operating activities and the change in working capital.

Net cash used in investing activities decreased$384 million to $1.1 billion in 2018 compared to $1.5 billion in 2017. The decrease was the result of lower cash paid for 2018 acquisitions, partially offset by proceeds from the 2017 sale of certain Alaska terminalling assets and WNRL’s lubricant operations located in Arizona and Nevada during 2017. We acquired the North Dakota Gathering and Processing Assets and an ownership interest in MPL during 2017 and the SLC Core Pipeline System and ownership interests in ALRP and PNAC in 2018. Partially offsetting these were higher cash spend on capital expenditures during 2018. See “Capital Expenditures” below for a discussion of the various maintenance and growth projects in 2018.

Net cash from financing activities during 2018 totaled $55 million as compared to $233 million in 2017. The decrease of $178 million was primarily due to lower proceeds from the issuance of debt, preferred units and common units of $1.8 billion, $589 million and $284 million, respectively, and an increase in quarterly distributions to common and preferred unitholders of $329 million and $29 million, respectively. These decreases in cash were partially offset by fewer repayments of long-term debt of $2.1 billion. Sponsor contributions of equity to the Predecessors and distributions in connection with Acquisitions from our Sponsor decreased by $368 million and $106 million, respectively. There were no distributions to our general partner or

December 31, 2018 |55

Management’s Discussion and Analysis

premiums paid on debt redemption during 2018 compared to $131 million and $85 million, respectively, during 2017. Borrowings under our revolving credit facilities increased by $95 million and repayments under our revolving credit facilities decreased by $654 million.

2017 Versus 2016

Net cash from operating activities increased$245 million to $687 million in 2017 from $442 million in 2016. The increase in net cash from operating activities was primarily due to an increase in net earnings after considering the impacts of non-cash operating activities and the change in working capital.

Net cash used in investing activities increased$875 million to $1.5 billion in 2017 compared to $658 million in 2016. The increase was primarily driven by the acquisition of WNRL, the 2018 Drop Down and the North Dakota Gathering and Processing Assets and increased capital expenditures, partially offset by proceeds from the sale of certain Alaska terminalling assets.

Net cash from financing activities during 2017 totaled $233 million as compared to $888 million in 2016. The change of $655 million was primarily due to an increase in repayments of long-term debt of $1.8 billion, quarterly distributions to common unitholders of $206 million and premiums paid on debt redemption of $85 million. Also, sources of cash associated with borrowings under our revolving credit facilities and proceeds from issuance of common units decreased by $226 million and $80 million, respectively. These decreases in cash were partially offset by increases in proceeds from the issuance of preferred units and debt of $589 million and $299 million, respectively, an increase in sponsor contributions of equity to the Predecessors of $227 million and a decrease in distributions in connection with Acquisitions from Andeavor and repayments under our revolving credit facilities of $354 million and $274 million, respectively.

Sponsor Contributions

Historically, the Predecessors’ sources of liquidity included cash generated from operations and funding from Andeavor. Cash receipts were deposited in Andeavor’s bank accounts and all cash disbursements were made from those accounts. However, the cash funding and receipts from operations of WNRL were deposited in WNRL bank accounts and the balance of cash prior to acquisition is shown as a reduction of cash used for acquisitions. Sponsor contributions of $374 million, $742 million and $515 million were included in cash from financing activities in 2018, 2017 and 2016, respectively, which funded the cash portion of the net loss attributable to the Predecessors.

Capital Expenditures

The Partnership’s operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to maintain assets and ensure 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. Maintenance capital expenditures include expenditures required to maintain equipment reliability and integrity and to ensure regulatory compliance. Actual and estimated amounts described below include amounts representing capitalized interest and labor. Our capital expenditures are funded primarily with cash generated from operations, reimbursements for certain growth and maintenance capital expenditures, borrowings under our Revolving Credit Facility and issuances of additional debt securities, as needed. In addition, although we have the ability to issue equity securities, new issuances are not included in our current funding plan.

2018 Capital Expenditures

During 2018, we spent $635 million, net of $32 million in reimbursements from entities including our Sponsor, on growth capital projects and $60 million, net of $24 million in reimbursements from entities including our Sponsor, on maintenance capital projects.

2019 Expected Capital Expenditures

We estimate that our expected 2019 capital expenditures will be approximately $800 million, or $700 million net of reimbursements from entities including our Sponsor, with whom we contract to provide services. We continuously evaluate our capital expenditures in light of conditions in the market environment and business requirements. Cost estimates for projects currently in process or under development are subject to further review, analysis and permitting requirements, which may result in revisions to our current spend estimates.

56 |

Management’s Discussion and Analysis

Major Capital Projects in Process or Under Development (in millions)

Major Projects	Total Project Expected Capital Expenditures		Actual 2018 Capital Expenditures (a)
Conan Crude Gathering System (b)	$	270	$	188
Carson Crude Terminal Expansion Project (c)		165	6
North Dakota NGL Logistics Hub (d)		160	137
Los Angeles Refinery Interconnect Pipeline System (e)		150	86

(a) Includes the historical results related to the Partnership and Predecessors.

(b) The construction of the Conan crude gathering system provides connectivity to multiple long-haul pipelines. The initial capacity is planned to be approximately 250 Mbpd, which is expandable to 500 Mbpd. The initial storage capacity is estimated to be 720,000 barrels. The project was transferred from our Sponsor to us in 2018 at cost plus capitalized interest.

(c) We intend to construct and operate two to three million barrels of additional crude oil storage capacity to better accommodate the unloading of marine vessels at our nearby marine terminal, which is expected to reduce transportation costs for Marathon, such as port fees and demurrage.

(d) We intend to transport mixed NGLs from a third party processing plant in McKenzie County, North Dakota to our Belfield gas processing plant for fractionation and then ship purity NGL products on manifest and unit trains from the Fryburg rail terminal.

(e) The pipeline interconnect project at Marathon’s Los Angeles refinery is designed to provide direct connectivity between Marathon’s refining sites. The project was transferred from our Sponsor to us in 2018 at cost plus capitalized interest.

Long-Term Commitments

We have numerous contractual commitments for purchases associated with the operation of our assets, our debt service and our operating and capital leases (see Note 8 and Note 10 to our consolidated financial statements in Item 8). We also have minimum contractual spending requirements for certain capital projects.

Summary of Contractual Obligations (in millions)

Contractual Obligation	2019		2020		2021		2022		2023		Thereafter		Total
Long-term debt obligations (a)	$	737	$	216	$	1,412	$	957	$	126	$	3,273	$	6,721
Capital lease obligations (b)	4		3		3		2		2		4		18
Operating lease obligations (c)	17		17		15		13		13		105		180
Purchase obligations (d)	2,078		2,084		2,054		2,013		2,013		1,673		11,915
Capital expenditure obligations (e)	297		—		—		—		—		—		297
Total Contractual Obligations	$	3,133	$	2,320	$	3,484	$	2,985	$	2,154	$	5,055	$	19,131

(a) Includes maturities of principal and interest payments. Amounts and timing may be different from our estimated commitments due to potential voluntary debt prepayments and borrowings.

(b) Capital lease obligations include amounts classified as interest.

(c) Minimum operating lease payments for operating leases having initial or remaining non-cancellable lease terms in excess of one year primarily related to our truck vehicle leases and leases for pipelines, terminals, pump stations and property leases.

(d) Purchase obligations include enforceable and legally binding service agreement commitments that meet any of the following criteria: (1) they are non-cancellable, (2) we would incur a penalty if the agreement was canceled, or (3) we must make specified minimum payments even if we do not take delivery of the contracted products or services. If we can unilaterally terminate the agreement simply by providing a certain number of days’ notice or by paying a termination fee, we have included the termination fee or the amount that would be paid over the notice period. Contracts that can be unilaterally terminated without a penalty are not included. Future purchase obligations primarily include our fuel costs associated with our wholesale product supply agreement, NGLs transportation costs, fractionation fees, and fixed charges under the Amended Omnibus Agreement and the 2019 Secondment Agreements. As we are unable to estimate the termination of the Amended Omnibus Agreement, we have included the fees for each of the five years following December 31, 2018 for disclosure purposes in the table above.

(e) Minimum contractual spending requirements for certain capital projects.

We also have other noncurrent liabilities pertaining to our environmental liabilities and asset retirement obligations. With the exception of amounts classified as current, there is uncertainty as to the timing of future cash flows related to these obligations. As such, we have excluded these future cash flows from the table above. See additional information on environmental liabilities and asset retirement obligations in Note 10 and Note 1, respectively, to our consolidated financial statements in Item 8.

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements, other than our leasing arrangements described in Note 10 to our consolidated financial statements in Item 8, that would result in off-balance sheet liabilities.

December 31, 2018 |57

Management’s Discussion and Analysis

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, we are indemnified 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 our Sponsor.

Environmental Liabilities and Legal

Contamination resulting from spills of crude oil, natural gas and refined products is not unusual within the terminalling, pipeline, gathering or processing industries. Historic spills at certain of our assets as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at our properties where releases of hydrocarbons and other wastes have occurred. A number of our properties have known hydrocarbon or other hazardous material contamination in the soil and groundwater. See below for our discussion of the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement for more information regarding the indemnification of certain environmental matters provided to us by our Sponsor.

We have been party to various environmental matters arising in the ordinary course of business. The outcome of these matters cannot always be accurately predicted, but we recognize 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 accruals 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 $6 million and $16 million at December 31, 2018 and 2017, respectively.

See Note 10 to our consolidated financial statements in Item 8 for additional information regarding our environmental liabilities and legal proceedings.

Indemnification

Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, our Sponsor 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 the subsequent acquisitions from our Sponsor. See Note 3 to our consolidated financial statements in Item 8 for additional information regarding our Amended Omnibus Agreement and the Carson Assets Indemnity Agreement.

Accounting Standards

Critical Accounting Policies and Estimates

Our significant accounting policies and recent accounting developments are described in Note 1 to our consolidated financial statements in Item 8. We prepare our financial statements in conformity with U.S. GAAP, which requires us to make estimates and assumptions about future events that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We believe that the following discussion of policies to be the most important to the portrayal of our financial condition and results of operations and require management’s most difficult, subjective and complex judgments.

Goodwill

Goodwill represents the excess of the consideration paid over the fair value of the net assets acquired in a business combination. Goodwill acquired in a business combination is not amortized, but instead tested for impairment at least annually or more frequently should an event occur or circumstances indicate that the carrying amount may be impaired. Such events or circumstances may be a significant change in business climate, economic and industry trends, legal factors, negative operating performance indicators, significant competition, changes in strategy or disposition of a reporting unit or a portion thereof. Goodwill impairment testing is performed at the reporting unit level on November 1 of each year and when circumstances change that might indicate impairment.

58 |

Management’s Discussion and Analysis

We test goodwill for impairment by performing an optional qualitative assessment process and/or using a quantitative assessment process. If we choose to perform a qualitative assessment process and determine it is more likely than not (that is, a likelihood of more than 50 percent) that the carrying value of the net assets is more than the fair value of the reporting unit, a quantitative assessment process is then performed; otherwise, no further testing is performed. We may elect not to perform a qualitative assessment process and, instead, proceed directly to a quantitative assessment process. For reporting units where the quantitative assessment process is performed, the carrying value of net assets, including goodwill, is compared to the fair value at the reporting unit level. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recorded for the difference between the carrying value and fair value of the reporting unit.

We elected to perform our annual goodwill impairment analysis using the quantitative assessment process on $1.1 billion of goodwill recorded in five reporting units. As part of our quantitative goodwill impairment process for the five reporting units, we engaged a third-party appraisal firm to assist in the determination of estimated fair value for each reporting unit. This determination includes estimating the fair value of each reporting unit using both the income and market approaches. The income approach requires management to estimate a number of factors for each reporting unit, including projected future operating results, economic projections, anticipated future cash flows and discount rates. The market approach estimates fair value using comparable marketplace fair value data from within a comparable industry grouping. The determination of the fair value of the reporting units requires us to make significant estimates and assumptions. These estimates and assumptions primarily include, but are not limited to, the selection of appropriate peer group companies, control premiums appropriate for acquisitions in the industries in which we compete, discount rates, terminal growth rates, and forecasts of revenue, operating income and capital expenditures.

We determined that no impairment charges resulted from our November 1, 2018 goodwill impairment assessments. The fair values of Crude Oil Gathering, Wholesale, Terminalling and Transportation reporting units were substantially in excess of their carrying values. Also, the fair value of our Natural Gas Gathering and Processing reporting unit exceeded its carrying value by more than 10%. There were no impairments of goodwill during the years ended December 31, 2018, 2017 and 2016.

Impairment of Long-Lived Assets

Long-lived assets (which include property, plant, and equipment and intangible assets) are evaluated for impairment whenever events or changes in business circumstances indicate the net book values of the assets may not be recoverable (for example, current period operating losses combined with a history of operating losses) by assessing whether the asset net book values are recoverable from estimated future undiscounted cash flows. The actual amount of an impairment loss to be recorded, if any, is equal to the amount by which the asset’s net book value exceeds its fair market value. Fair market value is based on the present values of estimated future cash flows in the absence of quoted market prices. Estimates of future cash flows and fair market values of assets require subjective assumptions with regard to several factors, including an assessment of global market conditions, future operating results and forecasts of the remaining useful lives of the assets. Actual results could differ from those estimates. Providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates.

Acquisitions

We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed with acquisitions, other than a combination under common control, at their estimated fair values as of the date of acquisition. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired is recorded as goodwill. Significant judgment is required in estimating the fair value of assets acquired. As a result, in the case of significant acquisitions, we obtain the assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical information and on expectations and assumptions about the future, considering the perspective of marketplace participants. While management believes those expectations and assumptions are reasonable, they are inherently uncertain. Unanticipated market or macroeconomic events and circumstances may occur, which could affect the accuracy or validity of the estimates and assumptions.

New Accounting Standards and Disclosures

New accounting standards and disclosures are discussed in Note 1 to our consolidated financial statements in Item 8.

December 31, 2018 |59

Quantitative and Qualitative Disclosure

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. As we do not own the refined products, natural gas or crude oil that are shipped through our pipelines, distributed through our terminals or held in our storage facilities, we have minimal direct exposure to risks associated with fluctuating commodity prices. In addition, our commercial agreements with our Sponsor are indexed for inflation and contain fuel surcharge provisions designed to substantially mitigate our exposure to increases in diesel fuel prices and the cost of other supplies used in our business. Our wholesale fuel business has exposure to commodity prices while the refined product is being transported but are mitigated by fixed margin contracts. Some of our gathering and processing assets in North Dakota have natural gas gathering and processing contracts structured as POP arrangements. Under these POP arrangements, we gather and process the producers’ natural gas and retain and market a portion of the natural gas and NGLs and remit a percentage of the proceeds to the producer. Under these arrangements, we will have exposure to fluctuations in commodity prices; however, this exposure is not expected to be material to our results of operations. Also, our exposure to commodity price risk related to imbalance gains and losses or to diesel fuel or other supply costs is not expected to be material to our results of our operations, financial position and cash flows and we do not intend to hedge our exposure.

We are exposed to 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 hedge our exposure using 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. Actual results may differ from our expectation above.

Under a keep-whole agreement, normally 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. We have an agreement with our Sponsor to transfer the market risk associated with the purchase of natural gas. See Note 3 to our consolidated financial statements in Item 8 for additional information on our keep-whole agreement.

Interest Rate Risk

Our use of fixed or variable rate debt directly exposes us to interest rate risk. 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 our current fixed rate debt may be higher than the current market. 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. The carrying and fair values of our debt were $5.0 billion and $4.9 billion at December 31, 2018, respectively, and $4.2 billion and $4.3 billion at December 31, 2017, respectively. The fair value of our debt was estimated primarily using quoted market prices. These carrying and fair values of our debt do not reflect the unamortized issuance costs, which are netted against 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 percentage point change in the interest rate associated with the borrowings outstanding would change annual interest expense by $2 million under our Revolving Credit Facility and $1 million under our Dropdown Credit Facility at December 31, 2018. 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 currently do not use interest rate swaps to manage our exposure to interest rate risk; however, we continue to monitor the market and our exposure, and may in the future enter into these transactions to mitigate risk. We believe in the short term we have acceptable interest rate risk and continue to monitor the risk on our long-term obligations. There was $945 million of borrowings outstanding under the Revolving Credit Facility, $300 million of borrowings outstanding under the Dropdown Credit Facility and there were no borrowings under the MPC Loan Agreement as of December 31, 2018.

60 |

Financial Statements

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Unitholders of Andeavor Logistics LP and the Board of Directors of Tesoro Logistics GP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Andeavor Logistics LP (the “Partnership“) as of December 31, 2018 and 2017, the related consolidated statements of operations, partners‘ equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements“). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership as of December 31, 2018 and 2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 28, 2019 expressed an unqualified opinion thereon.

Adoption of ASU No. 2014-09

As discussed in Note 13 to the consolidated financial statements, the Partnership changed its method of accounting for revenue from sales to customers in 2018 due to the adoption of ASU no. 2014-09, Revenue from Contracts with Customers (Topic 606).

Basis for Opinion

These financial statements are the responsibility of the Partnership‘s management. Our responsibility is to express an opinion on the Partnership‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ ERNST & YOUNG LLP

We have served as the Partnership‘s auditor since 2010.

San Antonio, Texas

February 28, 2019

December 31, 2018 |61

Financial Statements

Andeavor Logistics LP

Consolidated Statements of Operations

		Year Ended December 31,
	Note	2018 (a)			2017 (a)			2016 (a)
		(In millions, except per unit amounts)
Revenues:
Fee-based:
Affiliate	3	$	1,309		$	942		$	747
Third-party		591			656			819
Product-based: (b)
Affiliate	3	280			489			100
Third-party		200			1,162			3
Total Revenues	13	2,380			3,249			1,669
Costs and Expenses:
Cost of fuel and other (excluding items shown separately below) (b)		—			1,244			316
NGL expense (excluding items shown separately below)		206			265			2
Operating expenses (excluding depreciation and amortization)		885			691			560
General and administrative expenses		121			158			106
Depreciation and amortization expenses		368			313			233
(Gain) loss on asset disposals and impairments	2	4			(25		)	4
Operating Income		796			603			448
Interest and financing costs, net		(233		)	(330		)	(195		)
Equity in earnings of equity method investments	6	31			22			13
Other income, net		6			11			11
Net Earnings		$	600		$	306		$	277
Loss attributable to Predecessors	2	$	28		$	43		$	62
Net Earnings Attributable to Partners		628			349			339
Preferred unitholders’ interest in net earnings		(44		)	(3		)	—
General partner’s interest in net earnings, including IDRs		—			(79		)	(152		)
Limited Partners’ Interest in Net Earnings		$	584		$	267		$	187
Net earnings per limited partner unit:
Common - basic		$	2.57		$	2.11		$	1.87
Common - diluted		$	2.57		$	2.11		$	1.87
Weighted average limited partner units outstanding:
Common units - basic		228.7			126.0			98.2
Common units - diluted		228.9			126.1			98.2
Cash distributions paid per unit		$	4.0750		$	3.8062		$	3.3070

(a) All periods include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for year ended December 31, 2018 were netted. See Note 1 for further discussion.

The accompanying notes are an integral part of these consolidated financial statements.

62 |

Financial Statements

Andeavor Logistics LP

Consolidated Balance Sheets

		December 31,
	Note	2018		2017 (a)
		(In millions, except unit amounts)
Assets
Current Assets
Cash and cash equivalents		$	10	$	75
Receivables, net of allowance for doubtful accounts
Trade and other		195		219
Affiliate		279		264
Prepayments and other current assets	7	79		27
Total Current Assets		563		585
Property, Plant and Equipment, Net	4	6,845		6,249
Acquired Intangibles, Net	5	1,104		1,154
Goodwill	5	1,051		956
Equity Method Investments	6	602		440
Other Noncurrent Assets, Net		130		121
Total Assets		$	10,295	$	9,505
Liabilities and Equity
Current Liabilities
Accounts payable
Trade and other		$	214	$	186
Affiliate		252		207
Accrued interest and financing costs		41		40
Current maturities of debt	8	504		1
Other current liabilities	7	81		84
Total Current Liabilities		1,092		518
Debt, Net of Unamortized Issuance Costs	8	4,460		4,127
Other Noncurrent Liabilities		69		54
Total Liabilities		5,621		4,699
Commitments and Contingencies	10
Equity
Equity of Predecessors		—		1,292
Preferred unitholders: 600,000 units issued and outstanding in 2018 and 2017		604		589
Common unitholders: 245,493,184units issued and outstanding (217,097,057 in 2017)		4,070		2,925
Total Equity	11	4,674		4,806
Total Liabilities and Equity		$	10,295	$	9,505

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

The accompanying notes are an integral part of these consolidated financial statements.

December 31, 2018 |63

Financial Statements

Andeavor Logistics LP

Consolidated Statements of Partners’ Equity

	Equity of Predecessors (a)			Partnership									Non-controlling Interest			Total
				Common			Preferred			General Partner
	(In millions)
Balance at December 31, 2015	$	464		$	1,707		$	—		$	(13	)	$	84		$	2,242
Sponsor contributions of equity to the Predecessors	515			—			—			—			—			515
Loss attributable to Predecessors	(62		)	—			—			—			—			(62		)
Net liabilities not assumed by Andeavor Logistics LP	22			—			—			—			—			22
Allocation of net assets acquired by the unitholders	(322		)	310			—			12			—			—
Equity offering under ATM Program, net of issuance costs	—			71			—			—			—			71
Proceeds from issuance of units, net of issuance costs	—			293			—			—			—			293
Effect of deconsolidation of RGS	—			—			—			—			(84		)	(84		)
Distributions to unitholders and general partner	—			(324		)	—			(137		)	—			(461		)
Distributions to unitholders and general partner related to acquisitions	—			(679		)	—			(86		)	—			(765		)
Contributions	—			39			—			3			—			42
Net earnings excluding loss attributable to Predecessors	—			187			—			152			—			339
Other	—			4			—			3			—			7
Balance at December 31, 2016	$	617		$	1,608		$	—		$	(66	)	$	—		$	2,159
Sponsor contributions of equity to the Predecessors	2,464			—			—			—			—			2,464
Loss attributable to the Predecessors	(43		)	—			—			—			—			(43		)
Allocation of net assets acquired by the unitholders	(1,713		)	1,713			—			—			—			—
Proceeds from issuance of units, net of issuance costs	—			284			589			6			—			879
Unit-based compensation	—			5			—			—			—			5
Distributions to unitholders and general partner	(33		)	(501		)	—			(127		)	—			(661		)
Distributions to unitholders and general partner related to acquisitions	—			(401		)	—			—			—			(401		)
Contributions	—			50			—			3			—			53
Net earnings excluding loss attributable to Predecessors	—			229			—			120			—			349
General partner restructuring	—			(60		)	—			60			—			—
Other	—			(2		)	—			4			—			2
Balance at December 31, 2017	$	1,292		$	2,925		$	589		$	—		$	—		$	4,806
Sponsor contributions of equity to the Predecessors	374			—			—			—			—			374
Loss attributable to the Predecessors	(28		)	—			—			—			—			(28		)
Net liabilities not assumed by Andeavor Logistics LP	13			—			—			—			—			13
Allocation of net assets acquired by the unitholders	(1,651		)	1,651			—			—			—			—
Unit-based compensation	—			9			—			—			—			9
Distributions to common and preferred unitholders	—			(859		)	(29		)	—			—			(888		)
Distributions to unitholders related to acquisitions	—			(300		)	—			—			—			(300		)
Contributions	—			81			—			—			—			81
Net earnings excluding loss attributable to Predecessors	—			584			44			—			—			628
Cumulative effect of accounting standard adoption	—			(17		)	—			—			—			(17		)
Other	—			(4		)	—			—			—			(4		)
Balance at December 31, 2018	$	—		$	4,070		$	604		$	—		$	—		$	4,674

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

The accompanying notes are an integral part of these consolidated financial statements.

64 |

Financial Statements

Andeavor Logistics LP

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
	(In millions)
Cash Flows From (Used In) Operating Activities:
Net earnings	$	600		$	306		$	277
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation and amortization expenses	368			313			233
Amortization of debt issuance costs	10			10			9
Debt redemption charges	—			77			—
(Gain) loss on asset disposals and impairments	4			(25		)	4
Unit-based compensation expense	9			9			6
Distributions received in excess of equity in earnings of equity method investments	21			17			16
Other non-cash operating activities	—			(6		)	1
Changes in receivables	(17		)	24			(172		)
Changes in other current assets	(39		)	1			(6		)
Changes in current liabilities	104			3			81
Changes in other noncurrent assets and liabilities	(31		)	(42		)	(7		)
Net cash from operating activities	1,029			687			442
Cash Flows From (Used In) Investing Activities:
Capital expenditures	(770		)	(349		)	(298		)
Acquisitions, net of cash acquired	(379		)	(1,231		)	(332		)
Proceeds from sale of assets	—			47			—
Deposits for acquisitions	—			—			(33		)
Other investing activities	—			—			5
Net cash used in investing activities	(1,149		)	(1,533		)	(658		)
Cash Flows From (Used In) Financing Activities:
Proceeds from debt offering	—			1,750			1,451
Proceeds from issuance of common units, net of issuance costs	—			284			364
Proceeds from issuance of preferred units, net of issuance costs	—			589			—
Proceeds from issuance of general partner units, net of issuance costs	—			6			—
Quarterly distributions to common unitholders	(859		)	(530		)	(324		)
Distributions to preferred unitholders	(29		)	—			—
Quarterly distributions to general partner	—			(131		)	(137		)
Distributions in connection with acquisitions from our Sponsor	(300		)	(406		)	(760		)
Borrowings under revolving credit agreements	1,320			1,225			1,451
Repayments under revolving credit agreements	(498		)	(1,152		)	(1,426		)
Repayments of long-term debt including capital leases	(1		)	(2,070		)	(251		)
Premiums paid on debt redemption	—			(85		)	—
Sponsor contributions of equity to the Predecessors	374			742			515
Financing costs	—			—			(7		)
Payments of debt issuance costs	—			(22		)	(21		)
Contribution from general partner	—			—			4
Capital contributions by affiliate	51			34			29
Other financing activities	(3		)	(1		)	—
Net cash from financing activities	55			233			888
Increase (Decrease) in Cash and Cash Equivalents	(65		)	(613		)	672
Cash and Cash Equivalents, Beginning of Year	75			688			16
Cash and Cash Equivalents, End of Year	$	10		$	75		$	688

(a) All periods include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

The accompanying notes are an integral part of these consolidated financial statements.

December 31, 2018 |65

Notes to Consolidated Financial Statements

Note 1 - Organization and Basis of Presentation

Description and Nature of Business

Andeavor Logistics LP (“Andeavor Logistics” or the “Partnership”) is a growth-oriented Delaware limited partnership formed in December 2010 by Andeavor and its wholly-owned subsidiary, TLGP, our general partner, to own, operate, develop and acquire logistics and related assets and businesses. Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Andeavor 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 “Andeavor” or our “Sponsor” refer collectively to Andeavor for all activity through September 30, 2018, or Andeavor LLC, successor-by-merger to Andeavor effective October 1, 2018 and a wholly owned subsidiary of Marathon Petroleum Corporation, and any of Andeavor’s or Andeavor LLC’s subsidiaries, as applicable, other than Andeavor Logistics, its subsidiaries and its general partner. References in this report to “Marathon” or “MPC” refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries, including Andeavor LLC, or all of them taken as a whole.

Our logistics assets are integral to the success of Marathon’s refining and marketing operations and are used to gather crude oil and to distribute, transport and store crude oil and refined products. We are a full service logistics company operating primarily in the western and mid-continent regions of the United States. We own and operate a network of crude oil, refined products and natural gas pipelines as well as operate crude oil and refined products truck and marine terminals and provide crude oil and refined product storage capacity. In addition, we own and operate bulk petroleum distribution facilities and natural gas processing and fractionation complexes. Our assets are categorized into the following segments: Terminalling and Transportation, Gathering and Processing, and Wholesale. See Note 14 for additional information regarding our segments.

We generate revenues by charging fees for terminalling, transporting and storing crude oil and refined products, gathering crude oil and produced water, gathering and processing natural gas and selling fuel through wholesale commercial contracts. We are generally not directly exposed to commodity price risk with respect to any of the crude oil, natural gas, NGLs or refined products that we handle as part of our normal operations. However, we may be subject to limited commodity risk exposure due to pipeline loss allowance provisions in many of our pipeline gathering and transportation contracts and a nominal amount of condensate retained as part of our natural gas gathering services. For the NGLs that we handle under keep-whole agreements, the Partnership has a fee-based processing agreement with our Sponsor, 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. As part of the WNRL Merger, we acquired a wholesale fuel business that has exposure to commodity prices while the refined product is being transported but is mitigated by fixed margin contracts. In the years ended December 31, 2018, 2017 and 2016, 67%, 44% and 51% of our revenue, respectively, was derived from our Sponsor under various long-term, fee-based commercial agreements, the majority of which include minimum volume commitments, and from wholesale fuel sales to our Sponsor. QEP Resources accounted for 13% of our total revenues in the year ended December 31, 2016. No single customer, other than our Sponsor, accounted for more than 10% of our total revenues for the years ended December 31, 2018 and 2017.

Our Terminalling and Transportation segment consists of the Northwest Pipeline System, 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 regulated common carrier refined products pipeline system connecting Marathon’s Kenai refinery to our terminals in Anchorage, Alaska; tankage and related equipment at Marathon’s Kenai refinery; crude oil and refined products terminals and storage facilities in the western, southwest and midwestern U.S.; and storage facilities located at Marathon’s refineries. It also consists of marine terminals in California and in Washington; asphalt terminalling and processing services at our asphalt plant and terminal in El Paso, stand-alone asphalt terminals in the southwest as well as a 50% interest in PNAC. The segment also includes a rail-car unloading facility in Washington; a manifest rail facility in Washington; an asphalt trucking operation and a petroleum coke handling and storage facility in Los Angeles; and other pipelines that transport products and crude oil from Marathon’s refineries to nearby facilities in Salt Lake City and Los Angeles.

Our Gathering and Processing segment includes crude oil, natural gas, NGLs and produced water gathering systems in the Bakken Shale/Williston Basin area of the Bakken Region, the Green River Basin, the Rockies Region, the Permian Basin System and the Four Corners System. It also consists of the Great Northern Midstream and Fryburg pipelines, crude trucking operations and gas processing and fractionation complexes.

Our Wholesale segment includes the operations of several bulk petroleum distribution plants and a fleet of refined product delivery trucks that distribute commercial wholesale petroleum products primarily in Arizona, Colorado, Nevada, New Mexico and Texas. The refined product trucking business delivers a significant portion of the volumes sold by our Wholesale segment.

Principles of Consolidation and Basis of Presentation

The accompanying consolidated financial statements include the accounts of Andeavor Logistics and its subsidiaries. All intercompany accounts and transactions have been eliminated. We have evaluated subsequent events through the filing of this

66 |

Notes to Consolidated Financial Statements

Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements. We have not reported comprehensive income due to the absence of items of other comprehensive income in the years presented.

In 2018, 2017 and 2016, we entered into various transactions with our Sponsor and our general partner, TLGP, pursuant to which we acquired from our Sponsor the following:

• gathering, storage and transportation assets in the Permian Basin; legacy Western Refining assets and associated crude terminals; the majority of our Sponsor’s remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC on August 6, 2018. In addition, the Conan Crude Oil Gathering System and LARIP were transferred at cost plus incurred interest;

• crude oil, feedstock and refined products storage, the Anacortes marine terminal, a manifest rail facility and crude oil and refined products pipelines located in Anacortes, Washington on November 8, 2017;

• logistic assets owned by WNRL, which consisted of pipelines, gathering, terminalling, storage, transportation and wholesale fuel distribution assets effective October 30, 2017;

• tankage, refined product storage, marine terminal terminalling and storage assets, pipelines, causeway and ancillary equipment located in Martinez, California (the “Northern California Terminalling and Storage Assets”) effective November 21, 2016; and

• all of the limited liability company interests in Tesoro Alaska Terminals, LLC, tankage, bulk tank farm, a truck rack and rail-loading facility, terminalling and other storage assets located in Kenai, Anchorage and Fairbanks, Alaska (the “Alaska Storage and Terminalling Assets”) completed in two stages on July 1, 2016 and September 16, 2016.

These transactions are collectively referred to as “Acquisitions from our Sponsor” and the related assets, liabilities and results of the operations are collectively referred to as the “Predecessors.”

The Acquisitions from our Sponsor were transfers between entities under common control. As an entity under common control with our Sponsor, we record the assets that we acquired from our Sponsor on our consolidated balance sheet at our Sponsor’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 Andeavor Logistics have been retrospectively adjusted to include the historical results of the assets acquired in the Acquisitions from our Sponsor prior to the effective date of each acquisition. The acquisition of logistics assets located in Anacortes, Washington in 2017 was immaterial to our consolidated financial statements. While this acquisition is a common control transaction, prior periods have not been retrospectively adjusted as these assets do not constitute a business in accordance with ASU 2017-01, “Clarifying the Definition of a Business”. See Note 2 for additional information regarding the 2018, 2017 and 2016 acquisitions.

The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of our Predecessors at historical cost. The financial statements of our Predecessors have been prepared from the separate records maintained by our Sponsor and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Other than WNRL and certain assets acquired from the 2018 Drop Down, our Predecessors did not record revenue for transactions with our Sponsor. Accordingly, the revenues in our Predecessors’ historical combined financial statements relate only to amounts received from third parties for these services.

Use of Estimates

We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and revenues and expenses reported and presented as of and for the periods ended. 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.

Cash and Cash Equivalents

Cash and cash equivalents include bank deposits and low-risk, short-term investments with original maturities of three months or less at the time of purchase. Cash equivalents are stated at cost, which approximates market value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. We had no cash and cash equivalents held in money market funds.

Receivables

A portion of the Partnership’s accounts receivable is due from our Affiliates. Credit for non-affiliated customers is extended based on an evaluation of each customer’s financial condition and in certain circumstances, collateral, such as letters of credit or

December 31, 2018 |67

Notes to Consolidated Financial Statements

guarantees, is required. Our allowance for doubtful accounts is based on various factors including current sales amounts, historical charge-offs and specific accounts identified as high risk. After reasonable efforts to collect the amounts have been exhausted, balances are deemed uncollectible and are charged against the allowance for doubtful accounts. Write-offs were immaterial in 2018, 2017 and 2016. We do not have any off-balance-sheet credit exposure related to our customers.

Property, Plant and Equipment

Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and other allocated employee costs. Costs, including complete asset replacements and enhancements or upgrades that increase the original efficiency, productivity or capacity of property, plant and equipment, are also capitalized. The costs of repairs, minor replacements and maintenance projects that do not increase the original efficiency, productivity or capacity of property, plant and equipment are expensed as incurred. We capitalize interest as part of the cost of major projects during the construction period. Capitalized interest totaled $13 million, $8 million and $6 million for 2018, 2017 and 2016, respectively, and is recorded as a reduction to net interest and financing costs in our consolidated statements of operations.

We compute depreciation of property, plant and equipment using the straight-line method, based on the estimated useful life and salvage value of each asset. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as maintenance levels, economic conditions impacting the demand for these assets and regulatory or environmental requirements could cause us to change our estimates, thus impacting the future calculation of depreciation. We depreciate leasehold improvements and property acquired under capital leases over the lesser of the lease term or the economic life of the asset. Depreciation expense totaled $310 million, $262 million and $202 million for 2018, 2017 and 2016, respectively.

When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.

Asset Retirement Obligations

We record AROs at fair value in the period in which we have a legal obligation to incur costs, whether by government action or contractual arrangement, to retire a tangible asset and can make a reasonable estimate of the fair value of the liability. AROs are calculated based on the present value of the estimated removal and other closure costs using our credit-adjusted risk-free rate given an estimated settlement date for the obligation. We estimate settlement dates by considering our past practice, industry practice, management’s intent and estimated economic lives. We cannot currently estimate the fair value for certain potential AROs primarily because we cannot estimate settlement dates (or range of dates) associated with these assets. These AROs include, but are not limited to, the removal or dismantlement of terminal facilities, pipelines and other buildings. AROs included in our consolidated balance sheets were $10 million and $11 million at December 31, 2018 and 2017, respectively.

Acquired Intangibles and Goodwill

Acquired intangibles are recorded at fair value as of the date acquired and consist of customer relationships obtained in connection with the acquisitions of WNRL, the North Dakota Gathering and Processing Assets, and Andeavor Field Services, LLC, (the “Rockies Natural Gas Business Acquisition”). The value for the identified customer relationships consists of cash flow expected from existing contracts and future arrangements from the existing customer base. We amortize acquired intangibles with finite lives on a straight-line basis over an estimated weighted average useful life of 31 years and we include the amortization in depreciation and amortization expenses on our consolidated statements of operations.

Goodwill represents the amount the purchase price exceeds the fair value of net assets acquired in a business combination. We do not amortize goodwill or indefinite-lived intangible assets. The goodwill recorded for the acquisition of WNRL represents goodwill recognized by our Sponsor. Goodwill represents future organic growth opportunities, anticipated synergies and intangible assets that did not qualify for separate recognition. We are required, however, to review goodwill and indefinite-lived intangible assets for impairment annually, or more frequently if events or changes in business circumstances indicate that the asset might be impaired. In such circumstances, we record the impairment in loss on asset disposals and impairments in our consolidated statements of operations. We review the recorded value of goodwill for impairment on November 1^st of each year, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value using qualitative and/or quantitative assessments at the reporting level. There were no impairments of goodwill during the years ended December 31, 2018, 2017 and 2016.

Impairment of Long-Lived Assets

We review property, plant and equipment and other long-lived assets, including acquired intangibles with finite lives, for impairment whenever events or changes in business circumstances indicate the net book values of the assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than

68 |

Notes to Consolidated Financial Statements

the assets’ net book value. If this occurs, an impairment loss is recognized for the difference between the asset fair value and net book value. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset and a significant change in the asset’s physical condition or use.

Equity Method Investments and Joint Ventures

For equity investments that are not required to be consolidated under the variable interest model, we evaluate the level of influence we are able to exercise over an entity’s operations to determine whether to use the equity method of accounting. We use equity method of accounting when we are able to have significant influence over an entity’s operations. Our judgment regarding the level of control over an equity method investment includes considering key factors such as our ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in other noncurrent assets in our consolidated balance sheets and adjusted for our share of the net earnings or losses of the investee, which are presented separately in our statements of consolidated operations, capital contributions made and cash dividends received. We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. An impairment loss is recorded in earnings in the current period to write down the carrying value of the investment to fair value if a decline in the value of an equity method investment is determined to be other than temporary. There were no impairments of our equity method investments during the years ended December 31, 2018, 2017 and 2016.

Financial Instruments

Financial instruments including cash and cash equivalents, receivables, accounts payable and accrued liabilities are recorded at their carrying value. We believe the carrying value of these financial instruments approximates fair value. Our fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments and the expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

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 carrying value and fair value of our debt were $5.0 billion and $4.9 billion at December 31, 2018, respectively, and were $4.2 billion and $4.3 billion at December 31, 2017, respectively. These carrying and fair values of our debt do not consider the unamortized issuance costs, which are netted against our total debt.

Income Taxes

We are a limited partnership and, with the exception of three of our subsidiaries, are not subject to federal or state income taxes. Our taxable income or loss is included in the federal and state income tax returns of our partners. Taxable income may vary substantially from income or loss reported for financial reporting purposes due to differences in the tax bases and financial reporting bases of assets and liabilities, and due to certain taxable income allocation requirements of the partnership agreement. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units.

Contingencies

Environmental Matters

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. Our environmental liabilities are estimates using internal and third-party assessments and available information to date. It is possible these estimates will change as additional information becomes available.

We capitalize environmental expenditures that extend the life or increase the capacity of facilities as well as expenditures that prevent environmental contamination. We expense costs that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and the extent of remedial actions required by governing agencies, experience gained from similar sites for which environmental assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional liability and financial abilities of other responsible parties. Certain of our environmental liabilities, specific to long-term monitoring costs we believe are fixed and determinable, are recorded on a discounted basis. Where the available information is sufficient to estimate the amount of liability, that estimate is used. Where the information is only sufficient to establish a range of probable liability and no point within the range is more likely than another, the lower end of the range is used. Possible recoveries of some of these costs from other parties are not recognized in the financial statements until they become probable. Legal costs associated with environmental remediation are included as part of the estimated liability. The majority of our environmental liabilities are recorded on an undiscounted basis.

December 31, 2018 |69

Notes to Consolidated Financial Statements

Legal Matters

In the ordinary course of business, we become party to lawsuits, administrative proceedings and governmental investigations. These matters may involve large or unspecified damages or penalties that may be sought from us and may require years to resolve. We record a liability related to a loss contingency attributable to such legal matters in other current liabilities or other noncurrent liabilities on our consolidated balance sheets, depending on the classification as current or noncurrent if we determine the loss to be both probable and estimable. The liability is recorded for an amount that is management’s best estimate of the loss, or when a best estimate cannot be made, the minimum loss amount of a range of possible outcomes.

Acquisitions

We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed with acquisitions at their estimated fair values as of the date of acquisition, with the exception of the Acquisitions from our Sponsor. As an entity under common control with our Sponsor, we record the assets that we acquired from our Sponsor on our consolidated balance sheet at our Sponsor’s historical basis instead of fair value. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired from third parties is recorded as goodwill. While we use our best estimates and assumptions to measure the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date, our estimates are inherently uncertain and subject to refinement. As a result, during the measurement period, not to exceed one year from the date of acquisition, any changes in the estimated fair values of the net assets recorded for the acquisitions will result in an adjustment to goodwill. Upon the conclusion of the measurement period or final determination of the values of assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded to our consolidated statements of operations. Our acquisitions are discussed further in Note 2.

Revenue Recognition

See Note 13 for details of how we recognize revenue. See below for further discussion on our adoption of ASC 606.

Reimbursements

Pursuant to the Amended Omnibus Agreement and Carson Assets Indemnity Agreement, our Sponsor reimburses the Partnership for pressure testing, required repairs and maintenance identified as a result of the first inspection of certain pipeline and tank assets subsequent to the Acquisitions from our Sponsor, as well as maintenance projects identified in the Amended Omnibus Agreement for which the costs were not known at the date of the Acquisitions from our Sponsor. These amounts are recorded as a reduction to operating expense during the period the costs are incurred. These amounts were $15 million, $16 million and $17 million for the years ended December 31, 2018, 2017 and 2016, respectively.

In addition, our Sponsor reimburses the Partnership for capital projects identified in the Amended Omnibus Agreement. These amounts are recorded as a capital contribution by affiliate and were $51 million, $34 million and $29 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Imbalances

We experience volume gains and losses, which we sometimes refer to as imbalances, within our pipelines, terminals and storage facilities due to pressure and temperature changes, evaporation and variances in meter readings and in other measurement methods. On our crude oil gathering and transportation system in North Dakota and Montana (the “High Plains System”), we retain 0.20% of the crude oil shipped on our owned and operated common carrier pipelines in North Dakota and Montana and we bear any crude oil volume losses in excess of that amount. Under the Second Amended and Restated Master Terminalling Service Agreement, we retain 0.25% of the refined products we handle at certain of our terminals for Marathon, and bear any refined product volume losses in excess of that amount. The value of any crude oil or refined product imbalance settlements resulting from these tariffs or contractual provisions is determined by using the monthly average market prices for the applicable commodity, less a specified discount. The Partnership measures volume losses annually for the terminals and pipelines in the Northwest Pipeline System. We retain 0.125% of the distillates and 0.25% of the other refined products we handle at our terminals on the Northwest Pipeline System and we bear any refined product volume losses in excess of those amounts. The value of any refined product losses is determined by using the annual average market price for the applicable commodity. Any settlements under tariffs or contractual provisions where we bear any crude oil or refined product volume losses are recognized in the period they are realized.

There are pipeline loss allowance provisions associated with the pipeline agreements acquired in the WNRL Merger. There is a 0.20% pipeline loss allowance for the crude oil shipped on these pipeline systems. Each month we invoice our Sponsor for 0.20% of the volume delivered to us by our Sponsor for the month as a volume loss at a price equal to that month's calendar day average for WTI crude oil, as quoted on the New York Mercantile Exchange, less $8.00 per barrel. Following the end of the month, we calculate the actual volume loss and provide a credit to our Sponsor for the amount of actual volume loss at a price equal to the month's calendar day average for WTI crude oil, as quoted on the New York Mercantile Exchange, less $8.00 per barrel.

70 |

Notes to Consolidated Financial Statements

For all of our other terminals, and under our other commercial agreements with our Sponsor, we have no obligation to measure volume losses and have no liability for physical losses.

The consolidated balance sheets also include offsetting natural gas imbalance receivables or payables resulting from differences in gas volumes received by customers and gas volumes delivered to interstate pipelines. Natural gas volumes owed to or by the Partnership that are subject to tariffs are valued at market index prices, as of the balance sheet dates, and are subject to cash settlement procedures. Other natural gas volumes owed to or by the Partnership are valued at our weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.

Cost Classification

Cost of fuel and other includes the purchase cost of refined products sold within our Wholesale segment and the cost of inbound transportation and distribution costs incurred to transport product to our customers. NGL expense results from the cost of NGL purchases under our POP arrangements as well as the non-cash acquisition of replacement dry gas under our keep-whole arrangements associated with the acquired crude oil, natural gas and produced water gathering systems and two natural gas processing facilities from the North Dakota Gathering and Processing Assets.

Operating expenses are comprised of direct operating costs including costs incurred for direct labor, repairs and maintenance, outside services, chemicals and catalysts, utility costs, including the purchase of electricity and natural gas used by our facilities, property taxes, environmental compliance costs related to current period operations, rent expense and other direct operating expenses incurred in the provision of services.

Depreciation and amortization expenses consist of the depreciation and amortization of property, plant and equipment, deferred charges and intangible assets related to our operating segments along with our corporate operations. General and administrative expenses represent costs that are not directly or indirectly related to or otherwise are not allocated to our operations. Cost of fuel and other, NGL expense, direct operating expenses, and depreciation and amortization expenses recognized by our Terminalling and Transportation, Gathering and Processing, and Wholesale segments (refer to amounts disclosed in Note 14) constitute costs of revenue as defined by U.S. GAAP.

Unit-Based Compensation

Our general partner provides unit-based compensation to officers and non-employee directors for the Partnership, which includes service and performance phantom unit awards. The fair value of our service phantom unit awards on the date of grant is equal to the market price of our common units. We estimate the grant date fair value of performance phantom unit awards using a Monte Carlo simulation at the inception of the award. We amortize the fair value over the vesting period using the straight-line method. The phantom unit awards are settled in Andeavor Logistics common units. Expenses related to unit-based compensation are included in general and administrative expenses in our consolidated statements of operations. Total unit-based compensation expense totaled$9 million for the years ended December 31, 2018 and 2017 and $6 million for the year ended December 31, 2016. The Partnership had943,466units available for future grants under the long-term incentive plan at December 31, 2018.

Net Earnings per Limited Partner Unit

Effective October 30, 2017, we closed the WNRL Merger. Prior to the WNRL Merger, we used the two-class method when calculating the net earnings per unit applicable to limited partners, because we had more than one participating security consisting of limited partner common units, general partner units and IDRs. Net earnings earned by the Partnership were allocated between the limited and general partners in accordance with our partnership agreement. However, as a result of the IDR/GP Transaction in October 2017, our general partner and its IDRs no longer participate in earnings or distributions. See Note 2 for additional information regarding the WNRL Merger.

We base our calculation of net earnings per limited partner common unit on the weighted average number of common limited partner units outstanding during the period. Diluted net earnings per unit includes the effects of potentially dilutive units on our common units, which consist of unvested service and performance phantom units.

New Accounting Standards and Disclosures

Revenue Recognition

In May 2014, the FASB issued ASC 606 to replace existing revenue recognition rules with a single comprehensive model to use in accounting for revenue arising from contracts with customers. Under ASC 606, revenue is recognized when a customer obtains control of promised goods or services for an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, ASC 606 requires expanded disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

December 31, 2018 |71

Notes to Consolidated Financial Statements

We adopted ASC 606 on January 1, 2018 utilizing the modified retrospective method. We recognized a $17 million reduction to the opening balance of partners’ equity as of January 1, 2018 for the cumulative effect adjustment related to contracts in process but not substantially complete as of that date. We reflected the aggregate impact of all modifications executed and effective as of January 1, 2018 in applying the new standard to these contracts. The cumulative effect adjustment is primarily related to the period over which revenue is recognized on contracts for which customers pay minimum throughput volume commitments and claw-back provisions apply. Additionally, upon the adoption of ASC 606, the gross versus net presentation of certain contractual arrangements and taxes has changed as further described in Note 13. The current period results and balances are presented in accordance with ASC 606, while comparative periods continue to be presented in accordance with the accounting standards in effect for those periods.

For the year ended December 31, 2018, we recorded lower revenues of $2.6 billion and lower costs and expenses of $2.6 billion for presentation impacts of applying ASC 606. These impacts were primarily associated with the netting of revenues and costs associated with our fuel purchase and supply arrangements, as further described in Note 13. We recorded lower revenues of $6 million primarily associated with minimum volume commitments during the year ended December 31, 2018 as a result of applying the new standard. There were no material impacts during the period to the consolidated balance sheets or consolidated statement of consolidated cash flows, as a result of the adoption.

Leases

In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”) to record virtually all leases on the balance sheet. The ASU also requires expanded disclosures to help financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years. We transitioned to the new guidance by recording leases on our balance sheet as of January 1, 2019. We evaluated the impact of this standard on our financial statements, disclosures, internal controls and accounting policies. This evaluation process included reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path of implementing changes to existing processes and controls. We implemented a third-party supported lease accounting information system to account for our lease population in accordance with this new standard and established internal controls over the new system. We completed the design and testing of the new system and completed lease data loading and testing. We expect that adoption of the standard will result in the recognition of additional ROU assets and lease liabilities for operating leases in the range of approximately $115 million to $145 million.

Credit Losses

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”), which amends guidance on the impairment of financial instruments. The ASU requires the estimation of credit losses based on expected losses and provides for a simplified accounting model for purchased financial assets with credit deterioration. ASU 2016-13 is effective for annual reporting periods beginning after December 15, 2019, and interim reporting periods within those annual reporting periods. Early adoption is permitted for annual reporting periods beginning after December 15, 2018. While we are still evaluating the impact of ASU 2016-13, we do not expect to early adopt ASU 2016-13 nor expect the adoption of this standard to have a material impact on our consolidated financial statements.

Restricted Cash

In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" (“ASU 2016-18”), which clarifies how restricted cash and restricted cash equivalents are presented in the statements of cash flows. The ASU requires that changes in restricted cash that result from transfers between cash, cash equivalents and restricted cash should not be presented as cash flow activities in the statements of cash flows. ASU 2016-18 was effective for annual reporting periods beginning after December 15, 2017, and interim reporting periods within those annual reporting periods. We adopted ASU 2016-08 as of January 1, 2018 on a retrospective basis. Adoption of this standard resulted in an increase in cash and cash equivalents during the second quarter of 2017 of $14 million, but the restriction was released during the third quarter of 2017 as the cash was used to reinvest in assets used in our business and as a payment of debt. As a result, the adoption of this standard did not have an impact on our consolidated statement of cash flows for the year ended December 31, 2018.

Pension and Postretirement Costs

In March 2017, the FASB issued ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (“ASU 2017-07”), which requires the current service-cost component of net benefit costs to be presented similarly with other current compensation costs for related employees on the statement of consolidated operations and stipulates that only the service cost component of net benefit cost is eligible for capitalization. Additionally, the Partnership will present other components of net benefit costs elsewhere on the consolidated statements of operations since these costs are allocated to the Partnership’s financial statements by Marathon. The amendments to the presentation of the consolidated statements of operations in this update should be applied retrospectively while the change in capitalized benefit cost is to be applied prospectively. We adopted ASU 2017-07 as of January 1, 2018. Adoption of the standard resulted in an increase to interest and financing costs of $7 million with a corresponding increase to other income of $7 million for the year ended December 31, 2017 with no impact to net earnings. ASU 2017-07 does not impact the consolidated balance sheets or consolidated statements of cash flows.

72 |

Notes to Consolidated Financial Statements

Stock Compensation

In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718 to include share-based payment awards to nonemployees and eliminates the classification differences for employee and nonemployee share-based payment awards. This guidance is effective for interim and annual periods beginning after December 15, 2018. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.

Note 2 - Acquisitions

2018 Acquisitions

2018 Drop Down

On August 6, 2018, we completed the 2018 Drop Down for total consideration of $1.55 billion comprised of $300 million in cash financed with borrowings under our Dropdown Credit Facility and 28,283,742 newly issued common units of the Partnership with a fair value of $1.25 billion. These assets include gathering, storage and transportation assets in the Permian Basin; legacy Western Refining assets and associated crude terminals; the majority of Andeavor's remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC. In addition, the Conan Crude Oil Gathering System and the LARIP were transferred at cost plus incurred interest. In conjunction with the 2018 Drop Down, we entered into additional commercial agreements with Marathon. See Note 3 for further information regarding these agreements.

The 2018 Drop Down includes:

• Crude oil and other feedstock storage tankage and refined product storage tankage at Marathon’s Mandan, Salt Lake City and Los Angeles refineries;

• Rail terminals and truck racks at Marathon’s Mandan, Salt Lake City and Los Angeles refineries for the loading and unloading of various refined products from manifest and other railcars and trucks, respectively;

• Interconnecting pipeline facilities in the Los Angeles area as well as other railroad tracks and adjoining lands;

• Mesquite and Yucca truck unloading stations in New Mexico for the unloading of crude trucks and injection of crude into the TexNew Mex pipeline;

• Mason East and Jackrabbit (“Wink”) truck unloading and injection stations in Texas that receive crude via the T-Station line and trucks for injection into the Kinder Morgan and Bobcat Pipeline;

• The Jal storage, injection and rail unloading facility in New Mexico that stores and supplies natural gas liquids for use in Marathon’s El Paso refinery;

• Natural gas liquid storage tankage, a rail and truck terminal for the loading and unloading of natural gas liquids from railcars and trucks as well as from the waterline at the Wingate facility in New Mexico;

• Crude oil and other feedstock storage tankage at the Clearbrook terminal in Minnesota;

• Bobcat Pipeline that transports crude oil between the Mason East Station and the Wink Station;

• Benny Pipeline that delivers crude oil from the Conan terminal in Texas to a connection with gathering lines in New Mexico;

• All of the issued and outstanding limited liability company interests in: (i) Tesoro Great Plains Midstream LLC, which owns BakkenLink Pipeline LLC, (ii) Andeavor MPL Holdings LLC, which holds the investment in MPL, (iii) Andeavor Logistics CD LLC, (iv) Western Refining Conan Gathering, LLC, which owns the Conan Crude Oil Gathering System, (v) Western Refining Delaware Basin Storage, LLC, (vi) Asphalt Terminals LLC, which holds the investment in PNAC, and (vii) 67% of all of the issued and outstanding limited liability company interests in ALRP; and

• Certain related real property interests.

SLC Core Pipeline System

On May 1, 2018, we completed our acquisition of the SLC Core Pipeline System (formerly referred to as the Wamsutter Pipeline System) from Plains All American Pipeline, L.P. for total consideration of $180 million. The system consists of pipelines that transport crude oil to another third-party pipeline system that supply Salt Lake City area refineries, including Marathon’s Salt Lake City refinery. We financed the acquisition using our Revolving Credit Facility. This acquisition is not material to our consolidated financial statements and its operating results are reported in our Terminalling and Transportation segment.

2017 Acquisitions

Anacortes Logistics Assets

On November 8, 2017, we acquired the Anacortes Logistics Assets from a subsidiary of our Sponsor for total consideration of $445 million. The Anacortes Logistics Assets include crude oil, feedstock and refined products storage at Marathon’s Anacortes Refinery, the Anacortes marine terminal with feedstock and refined product throughput, a manifest rail facility and crude oil and refined products pipelines. We paid $445 million, including $400 million of cash financed with borrowings on our revolving credit facilities and $45 million in common units issued to our Sponsor.

December 31, 2018 |73

Notes to Consolidated Financial Statements

WNRL Merger

Effective October 30, 2017, we closed the WNRL Merger, exchanging all outstanding common units of WNRL for units of Andeavor Logistics, representing an equity value of $1.7 billion.

We accounted for the WNRL Merger as a common control transaction and, accordingly, inherited our Sponsor’s basis in WNRL’s net assets. Our Sponsor accounted for the acquisition of WNRL using the acquisition method of accounting, which requires, among other things, that assets acquired at their fair values and liabilities assumed be recognized on the balance sheet as of the acquisition date, or June 1, 2017, the date our Sponsor acquired WNRL. The purchase price allocation for the WNRL Merger has been allocated based on fair values of the assets acquired and liabilities assumed at the acquisition date. The allocation of the WNRL purchase price was final as of May 31, 2018. We recorded adjustments to the allocation to reduce property, plant and equipment and increase goodwill by $55 million during 2018.

Preliminary Acquisition Date Purchase Price Allocation (in millions)

Cash	$	22
Receivables	112
Inventories	11
Prepayments and Other Current Assets	25
Property, Plant and Equipment (a)	1,295
Goodwill	620
Acquired Intangibles	130
Other Noncurrent Assets	2
Accounts Payable	(167		)
Accrued Liabilities	(41		)
Debt	(347		)
Total purchase price	$	1,662

(a) Estimated useful lives ranging from 3 to 22 years have been assumed based on the valuation.

Goodwill

We evaluated several factors that contributed to the amount of goodwill presented above. These factors include the acquisition of a logistics business located in advantageous areas where there is crude oil marketing capabilities and meaningful refining offtake with an assembled workforce that cannot be duplicated at the same costs by a new entrant. Further, the WNRL Merger provides a platform for future growth through operating efficiencies we expect to gain from the application of best practices across the combined company and an ability to realize synergies from the geographic diversification of Andeavor Logistics’ business and rationalization of general and administrative costs. We allocated $374 million, $197 million and $49 million of goodwill to the Gathering and Processing, Terminalling and Transportation, and Wholesale segments, respectively.

Property, Plant and Equipment

The fair value of property, plant and equipment is $1.3 billion. This fair value is based on a valuation using a combination of the income, cost and market approaches. The useful lives are based on similar assets of the Partnership.

Acquired Intangible Assets

We estimated the fair value of the acquired identifiable intangible assets at $130 million. This fair value is based on a valuation completed for the business enterprise, along with the related tangible assets, using a combination of the income method, cost method and comparable market transactions. We recognized intangible assets associated with customer relationships of $130 million with third parties, all of which will be amortized on a straight-line basis over an estimated weighted average useful life of 15 years. The gross carrying value of our finite life intangibles acquired from the WNRL Merger was $130 million and the accumulated amortization was $14 million as of December 31, 2018. Amortization expense is expected to be approximately $9 million per year over the remaining useful life.

Acquisition Costs

We recognized acquisition costs related to the WNRL Merger of $17 million in general and administrative expenses and $3 million of severance costs for the year ended December 31, 2017.

WNRL Revenues and Net Earnings

For the years ended December 31, 2018 and 2017, we recognized $415 million and $1.5 billion, respectively, in revenues and $115 million and $40 million, respectively, of net earnings related to the business acquired. Revenues for 2018 were accounted for under ASC 606, further discussed in Notes 1 and 13. Net earnings for the year ended December 31, 2017 included related acquisition and severance costs.

74 |

Notes to Consolidated Financial Statements

Pro Forma Financial Information

The unaudited pro forma information combines the historical operations of Andeavor Logistics and WNRL, giving effect to the WNRL Merger and related transactions as if they had been consummated on January 1, 2017. For the year ended December 31, 2017, the unaudited pro forma consolidated revenues and net earnings was $4.3 billion and $403 million, respectively. Pro forma net earnings for the year ended December 31, 2017 includes a significant non-recurring adjustment to recognize the WNRL Merger acquisition and integration costs. We recognized acquisition costs related to the WNRL Merger of $17 million as well as $3 million of severance costs for the year ended December 31, 2017.

North Dakota Gathering and Processing Assets

On January 1, 2017, we acquired the North Dakota Gathering and Processing Assets for total consideration of $705 million, including payments for working capital amounts, funded with cash on-hand, which included borrowings under our Revolving Credit Facility. The North Dakota Gathering and Processing Assets include crude oil, natural gas, and produced water gathering pipelines, natural gas processing and fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. With this acquisition, we expanded the assets in our Gathering and Processing segment located in the Williston Basin area of North Dakota to further grow our integrated, full-service logistics capabilities in support of third-party demand for crude oil, natural gas and water gathering services as well as natural gas processing services. In addition, this acquisition increases our capacity and capabilities while extending our crude oil, natural gas and water gathering and associated gas processing footprint to enhance overall basin logistics efficiencies.

2016 Acquisitions

Northern California Terminalling and Storage Assets

Effective November 21, 2016, we acquired certain terminalling and storage assets located in Martinez, California from subsidiaries of our Sponsor for total consideration of $400 million, comprised of $360 million in cash financed with borrowings under our Dropdown Credit Facility, and the issuance of our equity securities with a fair value of $40 million. The Northern California Terminalling and Storage Assets include crude oil, feedstock, and refined product storage capacity at Marathon’s Martinez Refinery along with the Avon marine terminal capable of handling feedstock and refined product throughput. The equity consideration was comprised of 860,933 units in the form of common units and 17,570 units in the form of general partner units.

Alaska Storage and Terminalling Assets

Effective July 1, 2016, we entered into an agreement to purchase certain terminalling and storage assets owned by our Sponsor for total consideration of $444 million, which was completed in two phases. On July 1, 2016, we completed the acquisition of the first phase consisting of tankage, related equipment and ancillary facilities used for the operations at our Sponsor’s Kenai Refinery. The second phase was completed on September 16, 2016 and consisted of refined product terminals in Anchorage and Fairbanks. Consideration paid for the first phase was $266 million, comprised of $240 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of 162,375 general partner units and 390,282 common units to our Sponsor with a combined fair value of $26 million. Consideration paid for the second phase was $178 million, comprised of $160 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of 20,440 general partner units and 358,712 common units to our Sponsor with a combined fair value of $18 million.

December 31, 2018 |75

Notes to Consolidated Financial Statements

Combined Consolidated Financial Information

As discussed further in Note 1, we refer to the historical results of the Alaska Storage and Terminalling Assets (phase 1 prior to July 1, 2016 and phase 2 from June 20, 2016 to September 16, 2016), Northern California Terminalling and Storage Assets (prior to November 21, 2016), WNRL (from June 1, 2017 to October 30, 2017) and the 2018 Drop Down (prior to August 6, 2018), collectively as our “Predecessors.” The following tables present our results of operations disaggregated to present results relating to the Partnership and the Predecessors for the assets acquired from our Sponsor and the total amounts included in our combined consolidated financial statements for the years ended December 31, 2018, 2017 and 2016.

Reconciliation of Combined Financial Statements (in millions)

	Year Ended December 31, 2018
	Combined			Andeavor Logistics LP			Predecessors
Revenues:
Fee-based:
Affiliate	$	1,309		$	1,288		$	21
Third-party	591			582			9
Product-based:
Affiliate	280			280			—
Third-party	200			200			—
Total Revenues	2,380			2,350			30
Costs and Expenses
NGL expense (exclusive of items shown separately below)	206			206			—
Operating expenses (exclusive of depreciation and amortization)	885			845			40
General and administrative expenses	121			112			9
Depreciation and amortization expenses	368			346			22
Loss on asset disposals and impairments	4			4			—
Operating Income (Loss)	796			837			(41		)
Interest and financing costs, net	(233		)	(229		)	(4		)
Equity in earnings of equity method investments	31			15			16
Other income, net	6			5			1
Net Earnings (Loss)	$	600		$	628		$	(28	)
Loss attributable to Predecessors	28			—			28
Net Earnings Attributable to Partners	628			628			—
Preferred unitholders’ interest in net earnings	(44		)	(44		)	—
Limited Partners’ Interest in Net Earnings	$	584		$	584		$	—

76 |

Notes to Consolidated Financial Statements

	Year Ended December 31, 2017
	Combined			Andeavor Logistics LP			Predecessors
Revenues:
Fee-based:
Affiliate	$	942		$	796		$	146
Third-party	656			647			9
Product-based:
Affiliate	489			213			276
Third-party	1,162			495			667
Total Revenues	3,249			2,151			1,098
Costs and Expenses
Cost of fuel and other (excluding items shown separately below)	1,244			330			914
NGL expense (exclusive of items shown separately below)	265			265			—
Operating expenses (exclusive of depreciation and amortization)	691			554			137
General and administrative expenses	158			121			37
Depreciation and amortization expenses	313			255			58
Gain on asset disposals and impairments	(25		)	(24		)	(1		)
Operating Income (Loss)	603			650			(47		)
Interest and financing costs, net	(330		)	(321		)	(9		)
Equity in earnings of equity method investments	22			10			12
Other income, net	11			10			1
Net Earnings (Loss)	$	306		$	349		$	(43	)
Loss attributable to Predecessors	43			—			43
Net Earnings Attributable to Partners	349			349			—
Preferred unitholders’ interest in net earnings	(3		)	(3		)	—
General partner’s interest in net earnings, including IDRs	(79		)	(79		)	—
Limited Partners’ Interest in Net Earnings	$	267		$	267		$	—

December 31, 2018 |77

Notes to Consolidated Financial Statements

	Year Ended December 31, 2016
	Combined			Andeavor Logistics LP			Predecessors
Revenues:
Fee-based:
Affiliate	$	747		$	615		$	132
Third-party	819			502			317
Product-based:
Affiliate	100			100			—
Third-party	3			3			—
Total Revenues	1,669			1,220			449
Costs and Expenses
Cost of fuel and other (excluding items shown separately below)	316			—			316
NGL expense (exclusive of items shown separately below)	2			2			—
Operating expenses (exclusive of depreciation and amortization)	560			426			134
General and administrative expenses	106			94			12
Depreciation and amortization expenses	233			183			50
Loss on asset disposals and impairments	4			4			—
Operating Income (Loss)	448			511			(63		)
Interest and financing costs, net	(195		)	(196		)	1
Equity in earnings of equity method investments	13			13			—
Other income, net	11			11			—
Net Earnings (Loss)	$	277		$	339		$	(62	)
Loss attributable to Predecessors	62			—			62
Net Earnings Attributable to Partners	339			339			—
General partner’s interest in net earnings, including IDRs	(152		)	(152		)	—
Limited Partners’ Interest in Net Earnings	$	187		$	187		$	—

Divestitures

On June 2, 2017, due to our Sponsor’s consent decree with the state of Alaska associated with the acquisition of the Alaska Storage and Terminalling Assets, we sold one of our existing Alaska products terminals (“Alaska Terminal”) for $28 million. The sale resulted in a $25 million gain on sale in our consolidated statements of operations for the year ended December 31, 2017. The Alaska Terminal divestiture did not have a material impact on our operations.

Note 3 - Related-Party Transactions

Commercial Agreements

We have various long-term, fee-based commercial agreements with our Sponsor, under which we provide pipeline transportation, wholesale, trucking, terminal distribution and storage services to Marathon, and Marathon commits to provide us with minimum monthly throughput volumes of crude oil, refined products and other. If, in any calendar month, Marathon fails to meet its minimum volume commitments under these agreements, it will be required to pay us a shortfall payment. These shortfall payments may be applied as a credit against any amounts due above their minimum volume commitments for up to twelve months after the shortfall occurs. Each of these agreements has fees that are indexed annually for inflation or, in certain circumstances, allows for a quarterly rate adjustment based on a comparison of competitive rates.

78 |

Notes to Consolidated Financial Statements

Commercial Agreements with Marathon

				Termination Provisions
Commercial Agreement	Initiation Date	Term Years	Renewals	Refinery Shutdown Notice Period (a)	Force Majeure
Amended Transportation Services Agreement (High Plains System)	Apr-11	10	2 x 5 years	12 months	Unilateral
Second Amended and Restated Master Terminalling Agreement	Apr-11	10	2 x 5 years	12 months	Unilateral
Salt Lake City Storage Agreement	Apr-11	10	2 x 5 years	12 months	Unilateral
Amended and Restated Transportation Services Agreement (Salt Lake City Short Haul Pipeline)	Apr-11	10	2 x 5 years	12 months	Unilateral
Amorco Terminal Use and Throughput Agreement (Martinez Marine)	Apr-12	10	2 x 5 years	12 months	Unilateral
Transportation Services Agreement (LAR Short Haul Pipelines)	Sep-12	10	2 x 5 years	N/A	Unilateral
Amended Anacortes Track Use and Throughput Agreement	Nov-12	10	2 x 5 years	N/A	Unilateral
Long Beach Storage Services Agreement	Dec-12	10	2 x 5 years	N/A	Unilateral
Terminalling Services Agreement for Northwest Pipeline System	Jun-13	1	Year to year	N/A	Unilateral
Southern California Terminalling & Dedicated Services Agreement	Jun-13	10	2 x 5 years	N/A	Unilateral
Amended Carson Storage Services Agreement	Jun-13	10	2 x 5 years	N/A	Unilateral
Carson Tank Farm Storage Agreement	Jun-13	10	2 x 5 years	N/A	Unilateral
Amended Terminalling, Transportation and Storage Services Agreement (WNRL)	Oct-13	10	2 x 5 years	12 months	Unilateral
Amended Pipeline and Gathering Services Agreement (WNRL)	Oct-13	10	2 x 5 years	12 months	Unilateral
Carson Coke Handling Service Agreement	Dec-13	10	2 x 5 years	N/A	Unilateral
Amended and Restated Long Beach Berth Access Use and Throughput Agreement	Dec-13	10	2 x 5 years	N/A	Unilateral
Long Beach Pipeline Throughput Agreement (b)	Dec-13	10	2 x 5 years	N/A	Unilateral
Amended Transportation Services Agreement (SoCal Pipelines)	Dec-13	10	2 x 5 years	N/A	Unilateral
Bakken Area Storage Hub Storage - TRMC Tanks	Apr-14	5	2 x 5 years	N/A	Unilateral
Terminalling & Dedicated Storage Services Agreement - Martinez	Jul-14	10	2 x 5 years	N/A	Unilateral
Terminalling & Dedicated Storage Services Agreement - Anacortes	Jul-14	10	2 x 5 years	N/A	Unilateral
THPP Reversal Open Season Northbound Commitment	Sep-14	7	None	N/A	Unilateral
Tesoro Alaska Pipeline Throughput Agreement	Sep-14	10	2 x 5 years	N/A	Unilateral
Amended Crude Oil Trucking Transportation Services Agreement (WNRL)	Oct-14	10	None	N/A	Unilateral
Fuel Distribution and Supply Agreement (WNRL)	Oct-14	10	None	N/A	Unilateral
Amended Product Supply Agreement (WNRL)	Oct-14	10	None	N/A	Unilateral
Keep-Whole Commodity Fee Agreement	Dec-14	5	1 year auto	90 days prior to expiration	Bilateral
Sale of Natural Gas	Oct-15	1 month	Evergreen	N/A	Bilateral
Amended Asphalt Trucking Services Agreement (WNRL)	Jan-16	10	2 x 5 years	N/A	Unilateral
Green River Processing Crude Oil Sales Agreement	Feb-16	1	Evergreen	N/A	Bilateral
Tank #2030 Use, Storage and Throughput Agreement	Apr-16	6 months	6 months	N/A	Bilateral
Asphalt and Propane Rack Loading Services Agreement (Kenai)	May-16	10	2 x 5 years	N/A	Unilateral
Kenai Storage Services Agreement	Jul-16	10	2 x 5 years	N/A	Unilateral

December 31, 2018 |79

Notes to Consolidated Financial Statements

				Termination Provisions
Commercial Agreement	Initiation Date	Term Years	Renewals	Refinery Shutdown Notice Period (a)	Force Majeure
Terminalling, Transportation and Storage Services Agreement (St. Paul Park)	Sep-16	10	2 x 5 years	12 months	Unilateral
Alaska Terminalling Services Agreement	Sep-16	10	2 x 5 years	N/A	Unilateral
Martinez Storage Services Agreement	Nov-16	10	2 x 5 years	N/A	Unilateral
Avon Marine Terminal Use and Throughput Agreement	Jan-17	10	2 x 5 years	N/A	Unilateral
Belfield Crude & Oil Gathering	Jan-17	2	None	N/A	Unilateral
Amended Renewal Trucking Transportation Services Agreement	Apr-17	1	Evergreen	2 months prior to expiration	Unilateral
Transportation Services Agreement (Anacortes Short Haul Pipelines)	Nov-17	10	2 x 5 years	N/A	Unilateral
Anacortes Manifest Rail Terminalling Services Agreement	Nov-17	10	2 x 5 years	N/A	Unilateral
Anacortes Marine Terminal Operating Agreement	Nov-17	17	None	N/A	Unilateral
Storage Services Agreement - Anacortes II	Nov-17	10	2 x 5 years	N/A	Unilateral
Product Transportation Agreement (TRMC, WRSW, WRCLP, SPPRC)	Jan-18	1	Evergreen	N/A	Unilateral
Plant Dedication Agreement (Robinson Lake and Belfield)	Apr-18	3	Month to month	N/A	Bilateral
Product Sales Agreement - Robinson Lake	Apr-18	3	N/A	N/A	Bilateral
Product Sales Agreement - Belfield	Apr-18	3	N/A	N/A	Bilateral
Product Sales Agreement Y-Grade - Robinson Lake	May-18	1 month	Month to month	N/A	Bilateral
SLC Core Crude Throughput	May-18	0.2	Evergreen	N/A	Unilateral
Truck Loading (H2S) Little Knife	Jun-18	6	None	N/A	Unilateral
Truck Unloading Facility Throughput Agreement (Stanley LACT)	Jun-18	3	None	N/A	Unilateral
Transportation Services Agreement (LAR Interconnecting Pipelines)	Aug-18	10	2 x 5 years	12 months	Unilateral
Amended Master Terminalling Services Agreement - Clearbrook, Fryburg, Jal, LAR, Mandan, Wingate	Aug-18	10	2 x 5 years	N/A	Unilateral
Master Unloading and Storage Agreement (WNRL)	Aug-18	10	2 x 5 years	N/A	Unilateral
Amended Asphalt Terminalling, Transportation and Storage Services Agreement	Aug-18	10	2 x 5 years	30 days	Unilateral
Fryburg Terminal Services Agreement	Aug-18	2.6	1 month	N/A	Unilateral
Transloading Services Agreement - Salt Lake City Spur	Oct-18	3	None	N/A	Unilateral
Natural Gas Liquids Marketing Agreement	Oct-18	3	3 year extension with 60 days notice by AFS	N/A	Bilateral

(a) Fixed minimum volumes remain in effect during routine turnarounds.

(b) Agreement gives Marathon the option to renew for two five-year terms, or Marathon may modify the term of the agreements to a twenty-year term by providing notice in accordance with each agreement.

We charge fixed fees based on the total storage capacity of our assets under several of our agreements with Marathon. We recognized $407 million, $277 million and $193 million of revenue under these agreements where we were considered to be the lessor during the years ended December 31, 2018, 2017 and 2016, respectively. Committed minimum payments for each of the five years following December 31, 2018, are expected to be approximately $478 million to $530 million per year and an aggregate $1.5 billion remaining after 2023.

80 |

Notes to Consolidated Financial Statements

Fourth Amended and Restated Omnibus Agreement

We entered into an omnibus agreement with our Sponsor at the closing of our Initial Offering. The agreement has been amended for each of the Acquisitions from our Sponsor and was amended and restated in connection with the 2018 Drop Down. The amendment increased the annual administrative fee payable by us to our Sponsor under the Amended Omnibus Agreement to $17 million as of December 31, 2018, for the provision of various general and administrative services, including executive management, legal, accounting, treasury, human resources, health, safety and environmental, information technology, certain insurance coverage, administration and other corporate services. In addition, we reimburse our Sponsor for all other direct or allocated costs and expenses incurred by Marathon or its affiliates on our behalf. On January 1, 2019, the Amended Omnibus Agreement was further amended to add Marathon Petroleum Company LP (“MPCLP”) as a party to the agreement and to make certain other related conforming changes to reflect MPCLP’s addition.

Under the Amended Omnibus Agreement, Marathon indemnifies us for certain matters, including known environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and the subsequent acquisitions from our Sponsor, with certain exceptions that are covered by the Carson Assets Indemnity Agreement. With respect to assets that we acquired from our Sponsor, indemnification for unknown environmental and title liabilities is limited to pre-closing conditions identified prior to the earlier of the date that our Sponsor no longer controls our general partner or five years after the date of closing. The indemnification under the Initial Offering for unknown environmental matters expired on April 26, 2016. Under the Amended Omnibus Agreement, the aggregate annual deductible for each type of liability (unknown environmental liabilities or title matters) is $1 million as of December 31, 2018, before we are entitled to indemnification in any calendar year in consideration of Initial Offering assets and all subsequent acquisitions from our Sponsor, with the exception of the indemnifications for the acquisition of the six marketing and storage terminal facilities (the “Los Angeles Terminal Assets”) and the acquisition of the remaining logistics assets (the “Los Angeles Logistics Assets”) initially acquired by us as part of the Los Angeles acquisition in Southern California (the “Los Angeles Logistics Assets Acquisition”). In addition, with respect to the assets that we acquired from our Sponsor, we have agreed to indemnify Marathon for events and conditions associated with the ownership or operation of our assets that occur after the closing of the Initial Offering, and the subsequent acquisitions from our Sponsor, and for environmental liabilities related to our assets to the extent Marathon is not required to indemnify us for such liabilities. See Note 10 for additional information regarding the Amended Omnibus Agreement.

Carson Assets Indemnity Agreement

We entered into the Carson Assets Indemnity Agreement at the closing of the Los Angeles Logistics Assets Acquisition effective December 6, 2013, establishing indemnification for certain matters including known and unknown environmental liabilities arising out of the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the respective acquisition dates.

Under the Carson Assets Indemnity Agreement, our Sponsor retained responsibility for remediation of known environmental liabilities due to the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the respective acquisition dates, and has indemnified us for any losses incurred by us arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is limited to five years. However, with respect to Terminal 2 at the Long Beach marine terminal, which was included in the Los Angeles Logistics Assets Acquisition, the indemnification for unknown pre-closing remediation liabilities is limited to ten years. Indemnification of the Los Angeles Terminal Assets’ and the Los Angeles Logistics Assets’ environmental liabilities is not subject to a deductible. See Note 10 for additional information regarding the Carson Assets Indemnity Agreement.

Keep-Whole Commodity Fee Agreement

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 BTU content equivalent to the NGLs removed. The operating margin for these contracts is typically determined by the spread between NGLs sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). At that time, we entered into the Keep-Whole Commodity Agreement with our Sponsor. Under the Keep-Whole Commodity Agreement, our Sponsor pays us a processing fee for NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on our behalf. We pay our Sponsor a marketing fee in exchange for assuming the commodity risk.

In February 2016, the parties entered into the First Amendment to the Keep-Whole Commodity Agreement (the “Keep-Whole Amendment”) that adjusted the contract to provide for a tiered pricing structure for different NGL production levels. The Keep-Whole Amendment continues to provide for annual purchase orders setting forth service fees for the base and incremental volumes; however, the Keep-Whole Amendment provides that the service fees payable for incremental volumes of natural gas liquids above 315,000 gallons per day shall be calculated with reference to the costs of (i) processing, (ii) conditioning, (iii) handling, (iv) fractionation, (v) storage, truck and rail loading at the Blacks Fork processing complex, and (vi) pipeline transportation fees on the MAPL pipeline system and fractionation fees at Mt. Belvieu, Texas for transportation and fractionation services provided to processors by MAPL, Cedar Bayou Fractionators, and Enterprise Products Partners L.P. for natural gas

December 31, 2018 |81

Notes to Consolidated Financial Statements

liquids sold pursuant to the Keep-Whole Commodity Agreement. The pricing for both the base and incremental volumes are subject to revision each year.

Secondment Agreements

We entered into the Andeavor Secondment Agreement with Andeavor to govern the provision of seconded employees to or from Andeavor, the Partnership, and its subsidiaries, as applicable. On August 6, 2018, TLGP and certain of its indirect subsidiaries amended and restated the Andeavor Secondment Agreement. As amended and restated, the Amended Secondment Agreement incorporated the changes made in previous amendments into the body of the agreement and added WNRL and its affiliates as parties. The Andeavor Secondment Agreement also governed the use of certain facilities of the parties by the various entities. The services to be provided by such seconded employees, along with the fees for such services, were provided on the service schedules attached to the Andeavor Secondment Agreement. Specialized services and the use of various facilities, along with the fees for such services, will be provided for in service orders to be executed by parties requesting and receiving the service. For the years ended December 31, 2018, 2017 and 2016, we charged our Sponsor $8 million, $8 million and $5 million, respectively, and our Sponsor charged us $77 million, $29 million and $18 million, respectively, pursuant to the Andeavor Secondment Agreement.

On January 30, 2019, TLGP and certain of its indirect subsidiaries entered into the 2019 Secondment Agreements with MPLS and MRLS. Under the 2019 Secondment Agreements, MPLS and MRLS will second certain employees to occupy positions within our business and organization and to conduct business on our behalf. While seconded by MPLS and MRLS to us, seconded employees will remain on the payroll of MPLS or MRLS, as the case may be, and will be eligible to participate in all MPLS or MRLS benefit plans that they would be eligible to participate in absent the secondment, but will work for and be under our general direction, supervision and control. We will reimburse MPLS or MRLS, as the case may be, for the payroll costs of the seconded employees, including base pay, bonuses and other incentive compensation plus a burden rate associated with benefits and other payroll costs for the portion of the employee’s time that is allocated to us. The 2019 Secondment Agreements are for a term of 10 years, but may be sooner terminated by us, MPLS or MRLS upon 60 days written notice. In connection with the entry into the 2019 Secondment Agreements, on January 30, 2019, our Sponsor entered into an agreement (the “Termination Agreement”) that terminated the Andeavor Secondment Agreement. The Termination Agreement had an effective date of January 1, 2019.

Summary of Affiliate Transactions

Summary of Revenue and Expense Transactions with Marathon, including Predecessors (in millions)

	Year Ended December 31,
	2018		2017		2016
Revenues	$	1,589	$	1,431	$	847
Operating expenses (exclusive of depreciation and amortization) (a)	272		251		308
General and administrative expenses	98		101		80

(a) Includes net imbalance settlement gains of $12 million and $7 million in the years ended December 31, 2017 and 2016, respectively. Due to the adoption of ASC 606 effective January 1, 2018, imbalance settlement gains of $16 million in the year ended December 31, 2018 were included in revenues. Includes reimbursements primarily related to pressure testing and repairs and maintenance costs pursuant to the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement of $15 million, $16 million and $17 million in the years ended December 31, 2018, 2017 and 2016, respectively.

Predecessor Transactions

Related-party transactions of our Predecessors were settled through equity. The balance in receivables and accounts payable from affiliated companies represents the amount owed from or to Marathon related to certain affiliate transactions. Other than WNRL and certain assets acquired from the 2018 Drop Down, our Predecessors did not record revenue for transactions with Marathon.

Distributions

In accordance with our partnership agreement, our limited partner interests are entitled to receive quarterly distributions of available cash. We paid quarterly cash distributions to our Sponsor, including IDRs, totaling $493 million, $336 million and $245 million in 2018, 2017 and 2016, respectively. In connection with the IDR/GP Transaction, our general partner no longer holds IDRs.

On January 25, 2019, in accordance with our partnership agreement, we announced the declaration of a quarterly cash distribution, based on the results of the fourth quarter of 2018, of $1.03 per unit, of which $146 million was paid to Marathon on February 14, 2019, to unitholders of record on February 5, 2019.

82 |

Notes to Consolidated Financial Statements

Note 4 - Property, Plant and Equipment

Property, Plant and Equipment (in millions)

	Estimated Depreciable Lives (Years) (a)	December 31,
		2018			2017 (b)
Terminals and tankage	3 - 40	$	3,749		$	3,557
Pipelines	5 - 30	3,411			2,825
Land and leasehold improvements	3 - 29	297			282
Buildings and improvements	3 - 28	87			91
Other	1 - 28	82			142
Construction in progress	—	519			346
Property, Plant and Equipment, at Cost (c)		8,145			7,243
Accumulated depreciation (c)		(1,300		)	(994		)
Property, Plant and Equipment, Net		$	6,845		$	6,249

(a) The above excludes assets not being depreciated.

(b) Property, plant and equipment transferred to the Partnership in the 2018 Drop Down was recorded at historical costs. The Partnership recorded property, plant and equipment of $948 million and accumulated depreciation of $112 million as of December 31, 2017 in connection with the 2018 Drop Down.

(c) Assets owned by us for which we are the lessor under operating leases were $691 million and $643 million before accumulated depreciation of $224 million and $195 million as of December 31, 2018 and 2017, respectively.

Note 5 - Acquired Intangibles and Goodwill

Acquired Intangibles

The acquired intangible assets, net of accumulated amortization, were $1.1 billion and $1.2 billion at December 31, 2018 and 2017, respectively, consisting of customer relationships associated with WNRL, the North Dakota Gathering and Processing Assets and the natural gas processing and gathering operations from the Rockies Natural Gas Business Acquisition. The value for the identified customer relationships consists of cash flows expected from existing contracts and future arrangements from the existing customer base. Accumulated amortization was $156 million and $106 million at December 31, 2018 and 2017, respectively. Amortization expense of acquired intangible assets was $50 million, $46 million and $29 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, amortization expense is expected to be approximately $50 million per year through 2023.

Goodwill

Goodwill by Operating Segment (in millions)

	December 31,
	2018		2017 (a)
Terminalling and Transportation (b) (c)	$	284	$	260
Gathering and Processing (b) (c)	718		607
Wholesale (b)	49		89
Goodwill	$	1,051	$	956

(a) Adjusted to include the historical results of the Predecessors. See Note 1 for further discussion.

(b) In connection with the finalization of the purchase price allocation associated with the WNRL Merger during 2018, we reallocated goodwill amongst the segments.

(c) Goodwill transferred to the Partnership in the 2018 Drop Down was recorded at historical cost. We recorded goodwill of $39 million and $225 million in our Terminalling and Transportation and Gathering and Processing segments, respectively, as of December 31, 2017 as a result of the 2018 Drop Down.

For 2018, we elected to perform our annual goodwill impairment assessment using a quantitative assessment process on our goodwill. As part of our quantitative goodwill impairment process, we engaged a third-party appraisal firm to assist in the determination of estimated fair value. This determination includes estimating the fair value using both the income and market approaches. The income approach requires management to estimate a number of factors, including projected future operating results, economic projections, anticipated future cash flows and discount rates. The market approach estimates fair value using comparable marketplace fair value data from within a comparable industry grouping. The determination of the fair value requires

December 31, 2018 |83

Notes to Consolidated Financial Statements

us to make significant estimates and assumptions. These estimates and assumptions primarily include, but are not limited to, the selection of appropriate peer group companies, control premiums appropriate for acquisitions in the industries in which we compete, the discount rates, terminal growth rates, and forecasts of revenue, operating income and capital expenditures.

We determined that no impairment charges resulted from our November 1, 2018 goodwill impairment assessments. The fair value of our five reporting units was in excess of their carrying value. There were no impairments of goodwill during the years ended December 31, 2018, 2017 and 2016.

Note 6 - Equity Method Investments and Joint Ventures

For each of the following investments, we have the ability to exercise significant influence through our participation in the management committees, which make all significant decisions. However, since we have equal or proportionate influence over each committee as a joint interest partner and all significant decisions require the consent of the other investor(s) without regard to economic interest, we have determined that these entities should not be consolidated and apply the equity method of accounting with respect to our investments in each entity.

• ALRP - We own a 67% interest in ALRP, a recently constructed crude oil pipeline located in the Delaware and Midland basins in west Texas.

• MPL- We own a 17% interest in MPL, which owns and operates a crude oil pipeline in Minnesota.

• PNAC - We own a 50% interest in PNAC, which owns and operates an asphalt terminal in Nevada.

• RGS - We own a 78% interest in RGS, which owns and operates the infrastructure that transports gas from certain fields to several re-delivery points in southwestern Wyoming, including natural gas processing facilities that are owned by us or a third party.

• TRG - We own a 50% interest in TRG located in the southeastern Uinta Basin, which transports natural gas gathered by UBFS and other third-party volumes to gas processing facilities.

• UBFS - We own a 38% interest in UBFS, which owns and operates the natural gas gathering infrastructure located in the southeastern Uinta Basin.

Equity Method Investments (in millions)

	ALRP (a)			MPL (a)			PNAC (a)			RGS			TRG			UBFS			Total
Balance at December 31, 2016	$	—		$	—		$	—		$	281		$	40		$	16		$	337
Acquired interests	—			120			—			—			—			—			120
Equity in earnings	—			12			—			6			2			2			22
Distributions received	—			(12		)	—			(19		)	(5		)	(3		)	(39		)
Balance at December 31, 2017 (b)	—			120			—			268			37			15			440
Acquired interests	159			—			27			—			—			—			186
Equity in earnings (loss)	6			17			(1		)	5			3			1			31
Cumulative effect of accounting standard adoption	—			—			—			—			(3		)	—			(3		)
Distributions received	(5		)	(20		)	—			(20		)	(5		)	(2		)	(52		)
Balance at December 31, 2018 (b)	$	160		$	117		$	26		$	253		$	32		$	14		$	602

(a) These equity method investments were included in the 2018 Drop Down. Amounts were adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) The carrying amounts of our investments that exceed the underlying equity in net assets are amortized over the useful life of the underlying fixed assets and included in equity in earnings. The carrying amount of our investments in these equity method investments exceeded the underlying equity in net assets as shown below.

	December 31,
(in millions)	2018		2017 (c)
ALRP	$	75	$	—
MPL	34		35
PNAC	17		—
RGS	125		130
TRG	14		15
UBFS	6		6

(c) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

84 |

Notes to Consolidated Financial Statements

We acquired 67% of all of the issued and outstanding limited liability company interests in ALRP as part of the 2018 Drop Down. ALRP is a variable interest entity. We are not the primary beneficiary of ALRP under the partnership agreement because the Partnership and the other minor shareholder jointly direct the activities of ALRP that most significantly impact its economic performance. In addition, we have a 78% interest in RGS. ALRP and RGS are unconsolidated variable interest entities and we use the equity method of accounting with respect to our investments in each entity.

Note 7 - Other Current Assets and Liabilities

Other Current Assets (in millions)

	December 31,
	2018		2017 (a)
Deferred charges	$	45	$	—
Inventories	22		12
Prepayments	12		15
Total Other Current Assets	$	79	$	27

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

Other Current Liabilities (in millions)

	December 31,
	2018		2017 (a)
Deferred income	$	24	$	23
Taxes other than income taxes	22		20
Employee costs	11		7
Asset retirement obligation	10		11
Accrued environmental liabilities	4		12
Other	10		11
Total Other Current Liabilities	$	81	$	84

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

December 31, 2018 |85

Notes to Consolidated Financial Statements

Note 8 - Debt

Debt Balance, Net of Unamortized Issuance Costs (in millions)

	December 31,
	2018			2017
Revolving Credit Facility	$	945		$	423
Dropdown Credit Facility	300			—
MPC Loan Agreement	—			—
5.500% Senior Notes due 2019	500			500
3.500% Senior Notes due 2022 (a)	500			500
6.250% Senior Notes due 2022	300			300
6.375% Senior Notes due 2024	450			450
5.250% Senior Notes due 2025	750			750
4.250% Senior Notes due 2027 (a)	750			750
5.200% Senior Notes due 2047 (a)	500			500
Capital lease obligations	15			9
Total Debt	5,010			4,182
Unamortized issuance costs (a)	(46		)	(54		)
Current maturities, net of unamortized issuance costs	(504		)	(1		)
Debt, Net of Current Maturities and Unamortized Issuance Costs	$	4,460		$	4,127

(a) Unamortized discounts of $4 million and $5 million associated with these senior notes are included in unamortized issuance costs at December 31, 2018 and 2017, respectively.

The aggregate maturities of our debt, including the principal payments of our capital lease obligations, for each of the five years following December 31, 2018 are $504 million in 2019, $2 million in 2020, $1.2 billion in 2021, $802 million in 2022 and $1 million in 2023.

Revolving Credit Facility and Dropdown Credit Facility

We are party to our $1.1 billion Revolving Credit Facility and our $1.0 billion Dropdown Credit Facility (together, the “Credit Facilities”). On January 5, 2018, we amended our Credit Facilities to, among other things, (i) increase the aggregate commitments from $600 million to $1.1 billion, (ii) add certain financial institutions as additional lenders under the Revolving Credit Facility and (iii) make certain changes to our Credit Facilities to permit the incurrence of incremental loans (to be shared between the Credit Facilities), subject to the satisfaction of certain conditions. The total aggregate available facility limits for the Credit Facilities totaled $2.1 billion at December 31, 2018. The Credit Facilities mature on January 29, 2021.

On December 20, 2018, we amended our Credit Facilities to, among other things, (i) grant additional flexibility to the Partnership and its subsidiaries to create liens and incur indebtedness, subject to the negative financial covenant that requires us to maintain a Consolidated Leverage Ratio (as defined in the credit agreements) of no greater than 5.0 to 1.0 (or 5.5 to 1.0 during the two fiscal quarters following certain acquisitions), (ii) remove restrictions on the ability of the Partnership and its subsidiaries to make investments and (iii) grant additional flexibility to the Partnership and its subsidiaries to enter into acquisitions, sell or dispose of assets and enter into related party transactions. In addition, we amended our Credit Facilities to make certain legal and technical updates to the revolving credit facility agreements, including the removal of collateral and security provisions that are no longer applicable and changes to reflect the previously reported acquisition of Andeavor by MPC effective on October 1, 2018.

Our Revolving Credit Facility provided for total loan capacity of $1.1 billionas of December 31, 2018. Our Revolving Credit Facility is non-recourse to Marathon, except for TLGP, and is guaranteed by substantially all of our consolidated subsidiaries. As of December 31, 2018, there was $945 million in borrowings outstanding under the Revolving Credit Facility, which had unused credit availability of $155 million, or 14% of the borrowing capacity. The weighted average interest rate for borrowings under our Revolving Credit Facility was 4.33%at December 31, 2018.

As of December 31, 2018, the Dropdown Credit Facility provided for total loan availability of $1.0 billion. We had $300 million in borrowings outstanding under the Dropdown Credit Facility, which had unused credit availability of $700 million, or 70% of the borrowing capacity. The weighted average interest rate for borrowings under our Dropdown Credit Facility was 4.14%at December 31, 2018.

86 |

Notes to Consolidated Financial Statements

Covenants

Our Credit Facility agreements both contain representations and warranties, affirmative and negative covenants, and events of default that we consider usual and customary for agreements of these types. The sole financial covenant that we are required to maintain, as of the last day of the fiscal quarter, is a Consolidated Leverage Ratio (as defined in the Credit Facility agreements) of no greater than 5.00 to 1.00. As of December 31, 2018, we were in compliance with this financial covenant.

Loan Agreement

On December 21, 2018, we entered into the MPC Loan Agreement. Under the terms of the MPC Loan Agreement, MPC will make a loan to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding exceeding $500 millionat any one time. The MPC Loan Agreement matures and the entire unpaid principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, owed by the Partnership under the MPC Loan Agreement will become due and payable on December 21, 2023, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, at any time prior to the maturity date. Interest will accrue on the unpaid principal amount of the Loan at a rate equal to the sum of (i) the one-month term LIBOR for dollar deposits, plus (ii) a premium of175basis points (or such lower premium then applicable under the Partnership’s credit agreements). There were no borrowings under the MPC Loan Agreement during 2018.

WNRL Repayment

At the time of the WNRL Merger, WNRL had a $500 million senior secured revolving credit facility (“WNRL Revolving Credit Facility”) and $300 million of 7.5% senior notes (the “WNRL Senior Notes”). In connection with the WNRL Merger, all amounts outstanding were repaid with borrowings on the Revolving Credit Facility and the WNRL Revolving Credit Facility was terminated. In addition, the WNRL Senior Notes were repaid for $326 million, including accrued interest of $4 million and a premium of $22 million, with borrowings on the Revolving Credit Facility.

Senior Notes

5.500% Senior Notes Due 2019

In October 2014, we completed a private offering of $1.3 billion aggregate principal amount of senior notes pursuant to a private placement transaction conducted under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The $1.3 billion of aggregate principal senior notes consisted of $500 million senior notes due in 2019 (the “2019 Notes”) at 5.500%, which approximates the effective interest rate, and $800 million of 6.250% senior notes due in 2022 (the “6.250%2022 Notes”). The proceeds from the 2019 Notes were used to repay amounts outstanding under our Revolving Credit Facility and to fund the Rockies Natural Gas Business Acquisition. We completed a registered exchange offer to exchange the 2019 Notes for debt securities with substantially identical terms in April 2016.

The 2019 Notes have no sinking fund requirements. We may redeem some or all of the 2019 Notes prior to September 15, 2019, at a make-whole price, and at par thereafter, plus accrued and unpaid interest. The 2019 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

3.500% Senior Notes Due 2022

In November 2017, we issued $500 million aggregate principal amount of senior notes due in 2022 at 3.500% (the “3.500%2022 Notes”), which approximates the effective interest rate. The proceeds from the 3.500%2022 Notes were used to repay a portion of our 5.875% senior notes due in 2020 and 6.125% senior notes due in 2021, as well as borrowings under the Dropdown Credit Facility.

The 3.500%2022 Notes will mature on December 1, 2022 and have no sinking fund requirements. The 3.500%2022 Notes may be redeemable in whole at any time or in part from time to time, at our option, prior to November 1, 2022. We may redeem the 3.500%2022 Notes at a redemption price equal to the greater of 100% of the principal amount or the sum of the present value of the remaining scheduled principal and interest payments. The 3.500%2022 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of investment grade securities.

6.250% Senior Notes Due 2022

In October 2014, we issued the 6.250%2022 Notes, which approximates the effective interest rate. The proceeds from the 6.250%2022 Notes were used to fund a portion of the Rockies Natural Gas Business Acquisition. We used the net proceeds from the sale of 600,000 Preferred Units to primarily redeem $500 million principal amount of our 6.250%2022 Notes.

December 31, 2018 |87

Notes to Consolidated Financial Statements

The 6.250%2022 Notes have no sinking fund requirements. The 6.250%2022 Notes may be redeemed at premiums equal to 3.125% through October 15, 2019; 1.563% from October 15, 2019 through October 15, 2020; and at par thereafter, plus accrued and unpaid interest. The 6.250%2022 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

6.375% Senior Notes Due 2024

In May 2016, we issued $450 million aggregate principal amount of senior notes due in 2024 (the “2024 Notes”) at 6.375%, which approximates the effective interest rate. We used the proceeds of the offering to repay amounts outstanding under the Revolving Credit Facility and for general partnership purposes.

The 2024 Notes have no sinking fund requirements and we may redeem some or all of the 2024 Notes, prior to May 1, 2019, at a make-whole price plus accrued and unpaid interest, if any. On or after May 1, 2019, the 2024 Notes may be redeemed at premiums equal to 4.781% through May 1, 2020; 3.188% through May 1, 2021; 1.594% from May 1, 2021 through May 1, 2022; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 106.375% face value with proceeds from certain equity issuances through May 1, 2019. The 2024Notes are unsecured and guaranteed by all of our consolidated subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

5.250% Senior Notes Due 2025

In December 2016, we issued $750 million aggregate principal amount of the senior notes due in 2025 (the “2025 Notes”) at 5.250%, which approximates the effective interest rate. The proceeds from this offering were used to repay amounts outstanding under the Dropdown Credit Facility.

The 2025 Notes have no sinking fund requirements. We may redeem some or all of the 2025 Notes prior to January 15, 2021, at a make-whole price, plus any accrued and unpaid interest. On or after January 15, 2021, the 2025 Notes may be redeemed at premiums equal to 2.625% through January 15, 2022; 1.313% through January 15, 2023; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 105.250% of face value with proceeds from certain equity issuances through January 15, 2020. The 2025 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

4.250% Senior Notes Due 2027

In November 2017, we issued $750 million aggregate principal amount of senior notes due in 2027 (the “2027 Notes”) at 4.250%, which approximates the effective interest rate. The proceeds from the 2027 Notes were used to repay a portion of our 5.875% senior notes due in 2020 and 6.125% senior notes due in 2021, as well as borrowings under the Dropdown Credit Facility.

The 2027 Notes will mature on December 1, 2027 and have no sinking fund requirement. The 2027 Notes may be redeemable in whole at any time or in part from time to time, at our option, prior to September 1, 2027. We may redeem the 2027 Notes at a redemption price equal to the greater of 100% of the principal amount or the sum of the present value of the remaining scheduled principal and interest payments as defined in the prospectus supplement. The 2027 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of investment grade securities.

5.200% Senior Notes Due 2047

In November 2017, we issued $500 million aggregate principal amount of senior notes due in 2047 (the “2047 Notes”) at 5.200%, which approximates the effective interest rate. The proceeds from the 2047 Notes were used to repay a portion of our 5.875% senior notes due in 2020 and 6.125% senior notes due in 2021, as well as borrowings under the Dropdown Credit Facility.

The 2047 Notes will mature on December 1, 2047 and have no sinking fund requirements. The 2047 Notes may be redeemable in whole at any time or in part from time to time, at our option, prior to June 1, 2047. We may redeem the 2047 Notes at a redemption price equal to the greater of 100% of the principal amount or the sum of the present value of the remaining scheduled principal and interest payments as defined in the prospectus supplement. The 2047 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Marathon, except for TLGP, and contain customary terms, events of default and covenants for an issuance of investment grade securities.

88 |

Notes to Consolidated Financial Statements

Capital Lease Obligations

Our capital lease obligations relate to two leases of facilities used for trucking operations in North Dakota with initial terms of 15 years, with five-year renewal options, leases of vehicles and equipment and a right of way with an initial term of 31 years. The total cost of assets under capital leases was $18 million and $11 million at December 31, 2018 and 2017, respectively, and accumulated amortization was $4 million and $3 million at December 31, 2018 and 2017, respectively. We include the amortization of the cost of assets under capital leases in depreciation and amortization expenses in our consolidated statements of operations.

Future Minimum Annual Lease Payments, Including Interest for Capital Leases (in millions)

	December 31, 2018
2019	$	4
2020	3
2021	3
2022	2
2023	2
Thereafter	4
Total minimum lease payments	18
Less amount representing interest	(3		)
Capital lease obligations	$	15

Note 9 - Benefit Plans

Employees supporting our operations participate in the benefit plans and the employee thrift plan of Marathon. Marathon allocates expense to us for costs associated with the benefit plans based on the salaries of Marathon’s employees that provide services to us as a percentage of total Marathon salaries. The Predecessors were allocated expenses for costs associated with the benefit plans primarily based on the percentage of the Predecessors’ allocated salaries compared to our Sponsor’s total salaries. Our portion of our Sponsor’s employee benefit plan expenses was $35 million, $34 million and $25 million for the years ended December 31, 2018, 2017 and 2016, respectively. These employee benefit plan expenses and the related payroll costs are included in operating expenses and general and administrative expenses in our consolidated statements of operations and include amounts allocated to the Predecessors.

Note 10 - Commitments and Contingencies

Operating Leases, Purchase Obligations and Other Commitments

Future Minimum Annual Payments Applicable to all Non-Cancellable Operating Leases and Purchase Obligations (in millions)

	Payments Due by Period
	2019		2020		2021		2022		2023		Thereafter		Total
Purchase obligations	$	2,078	$	2,084	$	2,054	$	2,013	$	2,013	$	1,673	$	11,915
Operating leases	17		17		15		13		13		105		180
Total	$	2,095	$	2,101	$	2,069	$	2,026	$	2,026	$	1,778	$	12,095

We have various cancellable and non-cancellable operating leases related to land, trucks, terminals, right-of-way permits and other operating facilities. In general, these leases have remaining primary terms up to 26 years and typically contain multiple renewal options. Total lease expense for all operating leases, including leases with a term of one month or less, was $25 million, $19 million and $11 million for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 8 for information related to our capital leases. See Note 3 for a discussion of revenue recognized under agreements where we are considered the lessor.

Our purchase obligations include enforceable and legally binding service agreement commitments that meet any of the following criteria: (1) they are non-cancellable, (2) we would incur a penalty if the agreement was canceled or (3) we must make specified minimum payments even if we do not take delivery of the contracted products or services. If we can unilaterally terminate the agreement simply by providing a certain number of days’ notice or by paying a termination fee, we have included the termination fee or the amount that would be paid over the notice period. Contracts that can be unilaterally terminated without a penalty are

December 31, 2018 |89

Notes to Consolidated Financial Statements

not included. Future purchase obligations primarily include fuel costs associated with our wholesale product supply agreement, NGLs transportation costs, fractionation fees, and fixed charges under the Amended Omnibus Agreement and the 2019 Secondment Agreements.

Our Amended Omnibus Agreement remains in effect between the applicable parties until a change in control of the Partnership. As we are unable to estimate the termination of the omnibus agreement, we have included the fees for each of the five years following December 31, 2018 for disclosure purposes in the table above. Total expense under the Amended Omnibus Agreement and the Andeavor Secondment Agreement was $311 million, $232 million and $192 million for the years ended December 31, 2018, 2017 and 2016, respectively. In addition to these purchase commitments, we also have minimum contractual capital spending commitments for approximately $297 million in 2019.

Indemnification

Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, Marathon 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 the subsequent acquisitions from our Sponsor.

Under the Amended Omnibus Agreement, with respect to assets that we acquired from our Sponsor, excluding the Los Angeles Terminal Assets and the Los Angeles Logistics Assets, indemnification for unknown environmental and title liabilities is limited to pre-closing conditions identified prior to the earlier of the date that our Sponsor no longer controls our general partner or five years after the date of closing. Under the Amended Omnibus Agreement, the aggregate annual deductible for each type of liability (unknown environmental liabilities or title matters) is $1 million, as of December 31, 2018, before we are entitled to indemnification in any calendar year in consideration of the Initial Offering assets and all subsequent acquisitions from our Sponsor, with the exception of the Los Angeles Terminal Assets Acquisition and the Los Angeles Logistics Assets Acquisition. In addition, with respect to the assets that we acquired from our Sponsor, we have agreed to indemnify Marathon for events and conditions associated with the ownership or operation of our assets that occur after the closing of the Initial Offering, and the subsequent acquisitions from our Sponsor, and for environmental liabilities related to our assets to the extent Marathon is not required to indemnify us for such liabilities.

Under the Carson Assets Indemnity Agreement, our Sponsor retained responsibility for remediation of known environmental liabilities due to the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the acquisition dates, and has indemnified us for any losses we incurred arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is limited to five years. However, with respect to Terminal 2 at the Long Beach marine terminal, which was included in the Los Angeles Logistics Assets Acquisition, the indemnification for unknown pre-closing remediation liabilities is limited to ten years. Indemnification of the Los Angeles Terminal Assets’ and the Los Angeles Logistics Assets’ environmental liabilities are not subject to a deductible.

Other 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 we 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 our Sponsor 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 our Sponsor, will be our responsibility.

Environmental Liabilities

Changes in our Environmental Liabilities (in millions)

	Tioga Crude Oil Pipeline Release			Other Liabilities			Total
At December 31, 2016	$	16		$	6		$	22
Additions	19			1			20
Expenditures	(25		)	(1		)	(26		)
At December 31, 2017	10			6			16
Additions	1			5			6
Expenditures	(11		)	(5		)	(16		)
At December 31, 2018	$	—		$	6		$	6

90 |

Notes to Consolidated Financial Statements

Resolved Matters

Tioga, North Dakota Crude Oil Pipeline Release

In September 2013, we responded to the release of crude oil in a rural field northeast of Tioga, North Dakota (the “Crude Oil Pipeline Release”). This incident was covered by our pollution liability insurance policy, subject to a $1 million deductible and a $25 million loss limit in place at the time of the release. Pursuant to this policy, there were no insurance recovery receivables related to the Crude Oil Pipeline Release at both December 31, 2018 and 2017. The remediation costs of $93 million exceeded our policy loss limit by $68 million as of December 31, 2018. We received no insurance proceeds for the years ended December 31, 2018, 2017 and 2016.

Other than described above, we do not have any other material outstanding lawsuits, administrative proceedings or governmental investigations. See current legal proceedings in Item 3.

Note 11 - Equity and Net Earnings per Unit

We had 89,320,056 common public units and 600,000 preferred units outstanding as of December 31, 2018. Additionally, as of December 31, 2018, Marathon owned 156,173,128 of our common units, constituting a 64% ownership interest in us. Marathon also held 80,000 TexNew Mex Units and all of the outstanding non-economic general partner units as of December 31, 2018.

Unit Issuance

In connection with the 2018 Drop Down, we issued 28,283,742 common units to Andeavor.

In connection with the WNRL Merger, we issued 15,182,996 publicly held common units and 14,853,542 common units to subsidiaries of Andeavor. In addition, In October 2017, we issued 78,000,000 of our common units to TLGP in connection with the IDR/GP Transaction and converted our general partner units into non-economic general partner units.

In February 2017, we closed a registered public offering of 5.0 million common units representing limited partner interests at a public offering price of $56.19 per unit. The net proceeds of $281 million were used to repay borrowings outstanding under our Revolving Credit Facility and for general partnership purposes. Also, general partner units of 101,980 were issued for proceeds of $6 million.

In June 2016, we closed a registered public offering of 6.3 million common units, including the over-allotment option exercised by the underwriter for the purchase of an additional 825,000 common units, at a public offering price of $47.13 per unit. The net proceeds of $293 million were used for general partnership purposes, including debt repayment, acquisitions, capital expenditures and additions to working capital.

Issuance of Preferred Units

In December 2017, we issued and sold the Preferred Units, at a price to the public of $1,000 per unit. We used the net proceeds from the sale of the Preferred Units (i) to primarily redeem $500 million principal amount of our 6.250%2022 Notes, (ii) to repay a portion of the borrowings under our Revolving Credit Facility and (iii) to pay fees and expenses associated with the foregoing.

At any time on or after February 15, 2023, we may redeem the Preferred Units, in whole or in part at a redemption price of $1,000 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions up to, but not including, the date of redemption, whether or not declared. In addition, upon the occurrence of certain rating agency events as described in the prospectus, we may redeem the Preferred Units, in whole but not in part, at a price of $1,020 per Preferred Unit, plus an amount equal to all accumulated and unpaid distributions up to, but not including, the date of redemption, whether or not declared.

Distributions on the Preferred Units will accrue and be cumulative from the original issue date of the Preferred Units and will be payable semi-annually in arrears on the 15th day of February and August of each year through and including February 15, 2023, with the first such payment made on February 15, 2018, and after February 15, 2023, quarterly in arrears on the 15th day of February, May, August, and November of each year to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date. If any Distribution Payment Date otherwise would fall on a day that is not a business day, declared distributions will be paid on the immediately succeeding business day without the accumulation of additional distributions.

The initial distribution rate for the Preferred Units from and including the original issue date of the Preferred Units to, but not including, February 15, 2023 will be 6.875% per annum of the $1,000 liquidation preference per Preferred Unit (equal to $68.75 per Preferred Unit per annum). On and after February 15, 2023, distributions on the Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 4.652%.

TexNew Mex Units

At the effective time of the WNRL Merger, each WNRL TexNew Mex unit was automatically converted into a right to receive TexNew Mex Units, which has substantially equivalent rights and obligations as the WNRL TexNew Mex unit.

December 31, 2018 |91

Notes to Consolidated Financial Statements

Prior to any distributions of available cash to holders of common units, available cash with respect to any quarter will first be distributed to the holders of the TexNew Mex Units, pro rata, as of the record date, in an amount equal to 80% of the excess, if any, of (1) the TexNew Mex Shared Segment Distributable Cash Flow with respect to the applicable quarter over (2) the TexNew Mex Base Amount with respect to such quarter, less any amounts reserved with the consent of holders of a majority of the TexNew Mex Units in accordance with our partnership agreement. As of December 31, 2018, we had 80,000 TexNew Mex Units outstanding. We did not separately disclose these units in the consolidated balance sheets and consolidated statements of partners’ equity because the equity balance was less than $1 million as of December 31, 2018 and 2017. No distributions to TexNew Mex unitholders were declared during 2018 or 2017.

ATM Program

In August 2017, we filed a prospectus supplement to our shelf registration filed with the SEC in August 2015, authorizing the continuous issuance of up to an aggregate of $750 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 program referred to as our “2017 ATM Program”). During the year ended December 31, 2017, we issued an aggregate of 72,857 common units under our 2017 ATM Program, generating proceeds of $3 million before issuance costs. The net proceeds from sales under the 2017 ATM Program were used for general partnership purposes, which may include debt repayment, future acquisitions, capital expenditures and additions to working capital. There were no issuances in 2018.

On August 24, 2015, we filed a prospectus supplement to its shelf registration statement filed with the SEC in August 2015, authorizing the continuous issuance of up to an aggregate of $750 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 program referred to as the “2015 ATM Program”). During the year ended December 31, 2016, we issued under both the 2015 ATM Program an aggregate of 1,492,637 common units generating proceeds of $72 million before issuance costs.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders’ capital accounts based on their ownership interest at the time of issuance.

Net Earnings per Unit

Prior to the WNRL Merger, we used the two-class method when calculating the net earnings per unit applicable to limited partners, because we had more than one participating security consisting of limited partner common units, general partner units and IDRs. Net earnings earned by the Partnership were allocated between the limited and general partners in accordance with our partnership agreement. As a result of the IDR/GP Transaction, the general partner units no longer participate in earnings or distributions, including IDRs. With the issuance of the Preferred Units, earnings are allocated first to the Preferred Units equal to their fixed distribution rate. We base our calculation of net earnings per unit using the weighted-average number of common limited partner units outstanding during the period.

92 |

Notes to Consolidated Financial Statements

Net Earnings per Unit (in millions, except per unit amounts)

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
Net earnings	$	600		$	306		$	277
Special Allocation (b)	—			1			3
Net earnings, including special allocations	600			307			280
Distributions on Preferred Units (c)	(41		)	(3		)	—
Net earnings attributable to common units	559			304			280
General partner’s distributions	—			(6		)	(10		)
General partner’s IDRs (d)	—			(75		)	(148		)
Limited partners’ distributions on common units	(890		)	(611		)	(344		)
Distributions on common units greater than earnings	$	(331	)	$	(388	)	$	(222	)
General partner’s earnings:
Distributions	$	—		$	6		$	10
General partners IDRs (d)	—			75			148
Allocation of distributions (greater) less than earnings (e)	(28		)	(44		)	(65		)
Total general partner’s earnings	$	(28	)	$	37		$	93
Limited partners’ earnings on common units:
Distributions (f)	$	890		$	611		$	344
Special allocation (f)	—			(1		)	(3		)
Allocation of distributions greater than earnings	(303		)	(344		)	(157		)
Total limited partners’ earnings on common units	$	587		$	266		$	184
Weighted average limited partner units outstanding:
Common units - basic	228.7			126.0			98.2
Common units - diluted (g)	228.9			126.1			98.2
Net earnings per limited partner unit: (h)
Common - basic	$	2.57		$	2.11		$	1.87
Common - diluted	$	2.57		$	2.11		$	1.87

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) 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. The adjustment reflects the special allocation to common units held by TLGP for the interest incurred in connection with borrowings on the Dropdown Credit Facility in lieu of using cash on hand to fund the North Dakota Gathering and Processing Assets in 2017 and the Alaska Storage and Terminalling Assets acquisition in 2016.

(c) The Preferred Units entitle unitholders to receive preferred distributions on a semi-annually basis.

(d) IDRs entitled the general partner to receive increasing percentages, up to 50%, of quarterly distributions in excess of $0.3881 per unit per quarter. The amount above reflects earnings distributed to our general partner net of $50 million of IDRs for the year ended December 31, 2017 waived by TLGP. Our general partner no longer holds IDRs as a result of the IDR/GP Transaction.

(e) We have revised the historical allocation of general partner earnings to include the Predecessors’ losses of $28 million, $43 million and $62 million for the years ended December 31, 2018, 2017 and 2016, respectively.

(f) Distributions of earnings for limited partners’ common units for the years ended December 31, 2018 and 2017 is net of a $60 million and $25 million waiver, respectively, from our Sponsor in connection with the WNRL Merger.

(g) Diluted net earnings per unit include the effects of potentially dilutive units on our common units, which consist of unvested service and performance phantom units.

(h) Amounts may not recalculate due to rounding of dollar and unit information.

December 31, 2018 |93

Notes to Consolidated Financial Statements

Allocations of the General Partner’s Interest in Net Earnings (in millions, except percentage of ownership interest)

	Year Ended December 31,
	2018			2017			2016
Net earnings attributable to partners	$	628		$	349		$	339
Distributions on Preferred Units	(41		)	(3		)	—
General partner’s IDRs	—			(75		)	(148		)
Special allocation	—			1			3
Net earnings available to partners	$	587		$	272		$	194
General partner’s ownership interest (a)	—		%	—		%	2.0		%
General partner’s allocated interest in net earnings (b)	$	—		$	4		$	4
General partner’s IDRs	—			75			148
Allocation of Predecessors’ impact to general partner interest	(28		)	(43		)	(62		)
Total general partner’s interest in net earnings	$	(28	)	$	36		$	90

(a) In connection with the IDR/GP Transaction, our general partner units converted into non-economic general partner units.

(b) Prior to the IDR/GP Transaction, we allocated net earnings to our general partner based on its ownership interest.

Changes in the Number of Units Outstanding (in million units)

	Common	Preferred	General Partner	Total
At December 31, 2015	93.5	—	1.9	95.4
Issuances under ATM Program	1.4	—	—	1.4
Issuance of units in June 2016 for cash	6.3	—	—	6.3
Issuance in July 2016 in connection with the Alaska Storage and Terminalling Assets acquisition	0.4	—	0.2	0.6
Issuance in September 2016 in connection with the Alaska Storage and Terminalling Assets acquisition	0.4	—	—	0.4
Issuance in November 2016 in connection with the Northern California Terminalling and Storage Assets acquisition	0.9	—	—	0.9
Unit-based compensation awards	0.1	—	—	0.1
At December 31, 2016	103.0	—	2.1	105.1
Issuances under ATM Program	0.1	—	—	0.1
Issuance of units in February 2017 for cash	5.0	—	0.1	5.1
Issuance in October 2017 in connection with the WNRL Merger	108.0	—	—	108.0
Issuance in November 2017 in connection with the Anacortes Logistics Assets acquisition	1.0	—	—	1.0
Issuance of Preferred Units in December 2017	—	0.6	—	0.6
At December 31, 2017	217.1	0.6	2.2	219.9
Issuance in August 2018 in connection with the 2018 Drop Down	28.3	—	—	28.3
Unit-based compensation awards	0.1	—	—	0.1
At December 31, 2018	245.5	0.6	2.2	248.3

Equity Transactions related to Acquisitions

Distributions to unitholders and the general partner include $300 million, $406 million and $760 million in cash payments for Acquisitions from our Sponsor during 2018, 2017 and 2016, respectively. As an entity under common control with Marathon, we record the assets that we acquire from our Sponsor in our consolidated balance sheets at our Sponsor’s historical book value instead of fair value, and any difference in amounts paid compared to the historical book value of the assets acquired from our Sponsor is recorded within equity. The Acquisitions from our Sponsor resulted in net increases of $1.4 billion and $1.3 billion in our equity balance during 2018 and 2017, respectively, and a net decrease of $443 million in our equity balance during 2016. The 2017 increase includes $1.7 billion in basis received in connection with the WNRL Merger.

94 |

Notes to Consolidated Financial Statements

Cash Distributions

On January 25, 2019, in accordance with our partnership agreement, we announced the declaration of a quarterly cash distribution, based on the results of the fourth quarter of 2018, totaling $238 million, or $1.03 per limited partner unit. This distribution was paid on February 14, 2019 to unitholders of record on February 5, 2019.

During the year ended December 31, 2018, we paid distributions associated with our Preferred Units of $29 million. During January 2019, we declared a distribution associated with our Preferred Units in the amount of $21 million, which will be paid on February 15, 2019.

Our distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions are earned.

Total Quarterly Cash Distributions to General and Limited Partners (in millions)

	Year Ended December 31,
	2018			2017			2016
General partner’s distributions:
General partner’s distributions	$	—		$	(6	)	$	(10	)
General partner’s IDRs (a)	—			(75		)	(148		)
Total general partner’s distributions	$	—		$	(81	)	$	(158	)
Limited partners’ distributions:
Common	$	(890	)	$	(611	)	$	(344	)
Total limited partners’ distributions	(890		)	(611		)	(344		)
Total Cash Distributions	$	(890	)	$	(692	)	$	(502	)

(a) As a result of the IDR/GP Transaction that occurred on October 30, 2017, our general partner no longer receives IDRs.

Note 12 - Supplemental Cash Flow Information

Supplemental disclosure of cash activities includes interest paid, net of capitalized interest, of $209 million, $243 million and $165 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Supplemental Disclosures of Non-Cash Investing and Financing Activities (in millions)

	Year Ended December 31,
	2018		2017		2016
Capital expenditures included in accounts payable at period end	$	105	$	50	$	30
Capital expenditures included in affiliate payable at period end	—		—		8
Capital leases and other	—		—		2
Predecessors’ net liabilities not assumed by Andeavor Logistics	13		—		22
Receivable from affiliate for capital expenditures	26		4		4

December 31, 2018 |95

Notes to Consolidated Financial Statements

Note 13 - Revenues

We recognize revenue upon transfer of control of promised products or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those products or services. For the year ended December 31, 2018, revenues from contracts with customers were $2.0 billion, which excludes lease revenues of $425 million. Upon adoption of ASC 606, revenue is recognized net of amounts collected from customers for taxes assessed by governmental authorities on, and concurrent with, specific revenue-producing transactions.

Service Revenue

We generate service revenue for gathering and transporting crude oil, natural gas and water; processing and fractionating natural gas and NGLs; and terminalling, transporting, and storing crude oil and refined products. We perform these services under various contractual arrangements with our customers. Under fee-based arrangements, we receive a fixed rate per volumetric unit for services we provide. For many of these fee-based arrangements, customers are required to make deficiency payments when they do not meet their minimum throughput volume commitments. Some of these contracts allow our customers to claw-back all or a portion of prior deficiency payments against excess volumes in future periods. Under keep-whole arrangements, we gather and process natural gas from producer-customers, retain and sell extracted NGLs, and return to the producer Shrink Gas with an equivalent British thermal unit content of the NGLs retained. For these arrangements, we receive from the producer a combination of fixed rate-per unit of cash consideration as well as non-cash consideration in the form of retained NGLs. Other agreements with producers consist of POP arrangements for which we gather and purchase natural gas from the producers, process purchased natural gas, and sell resulting NGLs and shrink gas at market prices. Reimbursements of certain costs and fees received under these purchase arrangements are recorded as a reduction to NGL expense. See further discussion below on our accounting for product revenues related to the sales of products resulting from our processing activities.

We recognize service revenue over time, as customers simultaneously receive and consume the related benefits of the services that we stand ready to provide. Revenue is recognized using an output measure, such as the throughput volume or capacity utilization, as these measures most accurately depict the satisfaction of our performance obligations. Where contracts contain variable pricing terms, the variability is either resolved within the reporting period, or the variable consideration is allocated to the specific unit of service to which it relates. Deficiency payments under contracts with claw-back provisions are deferred and recognized as revenue as customers reclaim amounts by throughputting excess volumes. To the extent it is probable a customer will not recover all or a portion of the deficiency payment, the estimated residual deficiency is recognized ratably over the claw-back period. Payments for services rendered are generally received no later than 60 days from the month of service, with the exception of deficiency payments described above.

For our keep-whole arrangements, we recognize service revenue for the fair value of non-cash consideration we receive in the form of NGLs. We obtain control of the NGLs we receive from our customers, have discretion in establishing price and have the ability to direct their use. We estimate the fair value of non-cash consideration at the date we obtain control of the respective NGLs, using the monthly average published price of underlying commodity adjusted for geography and commodity specifications.

We experience volume gains and losses, which we sometimes refer to as imbalances, within our pipelines, terminals and storage facilities due to pressure and temperature changes, evaporations and variances in meter reading in other measurement methods. Some of our arrangements require us to bear losses when actual volume losses exceed a contractually specified percentage. Similarly, we receive a benefit when actual volume losses are lower than the contractually specified percentage. For gains and losses which are cash settled, we include the settlement amounts in our service revenues. We recognize non-cash consideration for the stated percentage of commodity we retain and control. We record this non-cash consideration at fair value on a gross basis in service revenue and operating expense. The total amount of service revenue and NGL expense recorded associated with these arrangements is not material to our consolidated statements of operations.

Product Revenue

We generate product revenue from the sale of NGLs and related products along with the sale of gasoline and diesel fuel within our wholesale business. We sell NGLs, Shrink Gas and condensate using natural gas we acquire from producers under our POP arrangements. We record revenues for the sale of these NGLs and related products at market prices, and record the payments to producers for the agreed-upon percentage of the total sales proceeds as NGL expense, net of certain charges, which is reported within costs and expenses in our consolidated statements of operations.

We have certain fuel purchase and sale arrangements under which we receive minimum guaranteed margins with upside potential on a portion of our branded and unbranded fuel sales. Marathon retains control of fuel and is the principal in these affiliate arrangements. Therefore, we net the purchase and sale of fuel in our consolidated statements of operations.

NGLs received under keep-whole arrangements are sold to our affiliate. In return, we receive shrink gas which we then remit to the producers. This transaction is treated as a sale, for which we record the fair value of the non-cash consideration at the date we obtain control of the shrink gas. We utilize a monthly average of the published price of the commodity, adjusted for geography.

96 |

Notes to Consolidated Financial Statements

Our product sales arrangements are for specified goods for which enforceable rights and obligations are created when sales volumes are determined, which typically occurs as orders are issued or spot sales are made, but may be determined at contract inception. Each barrel, gallon or other unit of measure of product, is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated based on stand-alone selling price. We use observable market prices for the products we sell to determine the stand-alone selling price of each separate performance obligation. Product revenues are recognized at a point-in-time, which generally occurs upon delivery and transfer of title to the customer. Payments for product sales are generally received within 30 days from when control has transferred.

Other Arrangements

Based on the terms of certain storage and other agreements in which the counterparty is primarily our Sponsor, we are considered to be the lessor under these implicit operating lease arrangements. Income from these leases is excluded from the scope of the new revenue standard.

Customer Contract Assets

Our receivables are primarily associated with customer contracts. Our payment terms vary by product or service type, and the period between invoicing and payment is not significant. Included in our receivables are balances associated with commodity sales on behalf of our producer customers, for which we remit the net sales price back to the producer customers upon completion of each sale. These balances are commingled in our receivables, net of allowance for doubtful accounts in our consolidated balance sheets. Our contract assets include amounts recognized for deficiency payments associated with minimum volume commitments which have not been billed to customers. These contract assets are included in prepayments and other current assets in our consolidated balance sheets and are shown in the “Summary of Customer Contract Assets and Liabilities” table below.

Customer Contract Liabilities

For certain products or services, we receive payment in advance of when performance obligations are satisfied. These liabilities from contracts with customers consist primarily of certain deficiency payments for minimum volume commitments and customer reimbursements of costs for capital projects. Customer advances for capital projects are generally recognized over the contract term. We do not have a material impact for financing components associated with these customer advances. Payments for minimum volume commitments and other customer advances are included in deferred income within other current liabilities and other noncurrent liabilities based on timing of expected recognition, which generally extend up to 15 years. During the year ended December 31, 2018, we recognized $29 million in revenue from contract liabilities existing as of January 1, 2018, after cumulative adjustments for the adoption of ASC 606.

Summary of Customer Contract Assets and Liabilities (in millions)

	December 31, 2017 (a)	Adjustments for ASC 606 (b)(c)	Balance at January 1, 2018	December 31, 2018
Contract assets	—	34	34	32
Deferred income, current	23	—	23	24
Deferred income, noncurrent	43	16	59	57

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) These amounts exclude balances associated with equity method investments. We recognized a cumulative adjustment of $3 million as a decrease to Equity Method Investments in our consolidated balance sheets as of January 1, 2018 for the impacts related to our equity method investment in TRG. There were no material impacts to this balance during the year ended December 31, 2018 due to the adoption.

(c) Included in the $34 million change to contract assets is a $32 million reclass from Receivables for amounts for which we were not allowed to invoice as of January 1, 2018.

Remaining Performance Obligations

We do not disclose the value of unsatisfied performance obligations for contracts with original expected terms of one year or less or the value of variable consideration related to unsatisfied performance obligations, when such values are not required to be estimated for purposes of allocation and recognition. Revenues associated with remaining obligations under contracts with terms in excess of one year related primarily to arrangements for which the customer has agreed to fixed consideration based on minimum throughput volume commitments or capacity utilization. As of December 31, 2018, we had $4.0 billion of expected revenues from remaining performance obligations.

The future revenues from our service arrangements with fixed fees or minimum throughput volume commitments will be recognized over the period of performance to which the fixed fee or commitment relates, which generally ranges from 1 year to 15 years. We expect approximately 85% of our total remaining obligations to be recognized within 5 years.

December 31, 2018 |97

Notes to Consolidated Financial Statements

Disaggregation

We disaggregate our revenues by product and services, and further by product line. For additional information regarding our operating segments, see Note 14.

Revenue Disaggregation by Type and Product Line (in millions)

	Year Ended December 31, 2018
	Terminalling and Transportation (a)		Gathering and Processing (a)		Wholesale
Service Revenues (b)
Refined products	$	898	$	—	$	17
Crude oil and water	153		438		—
Natural gas	—		391		—
Other	3		—		—
Total Service Revenues	1,054		829		17
Product Revenues
NGL products	—		434		—
Refined products	—		—		46
Total Product Revenues	—		434		46
Total Revenues	$	1,054	$	1,263	$	63

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) Includes $425 million of lease revenues for the year ended December 31, 2018.

Note 14 - Operating Segments

Our revenues are derived from three operating segments: Terminalling and Transportation, Gathering and Processing and Wholesale. Refer to Note 1 for discussion of the operations included within each of our operating segments.

We evaluate the performance of our segments based primarily on segment operating income and EBITDA. For the purposes of our operating segment disclosure, we present operating income as it is the most comparable measure to the amounts presented in our statements of consolidated operations. Segment operating income includes those revenues and expenses that are directly attributable to management of the respective segment. Certain general and administrative expenses, interest and financing costs and equity in earnings of equity method investments 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.

98 |

Notes to Consolidated Financial Statements

Segment Information (in millions)

	Year Ended December 31,
	2018 (a)			2017 (a)			2016 (a)
Revenues
Terminalling and Transportation:
Terminalling	$	888		$	690		$	480
Pipeline transportation	160			130			125
Other revenues	6			18			—
Total Terminalling and Transportation	1,054			838			605
Gathering and Processing:
NGL sales	436			369			103
Gas gathering and processing	330			333			264
Crude oil and water gathering	336			262			582
Pass-thru and other	161			165			115
Total Gathering and Processing	1,263			1,129			1,064
Wholesale:
Fuel sales (b)	46			1,267			—
Other wholesale	33			15			—
Total Wholesale	79			1,282			—
Intersegment wholesale revenues	(16		)	—			—
Total Segment Revenues	$	2,380		$	3,249		$	1,669
Segment Operating Income
Terminalling and Transportation	$	498		$	397		$	240
Gathering and Processing	310			245			235
Wholesale	27			15			—
Total Segment Operating Income	835			657			475
Unallocated general and administrative expenses	(39		)	(54		)	(27		)
Operating Income	796			603			448
Interest and financing costs, net	(233		)	(330		)	(195		)
Equity in earnings of equity method investments	31			22			13
Other income, net	6			11			11
Net Earnings	$	600		$	306		$	277
Depreciation and Amortization Expense
Terminalling and Transportation	$	144		$	117		$	95
Gathering and Processing	213			191			138
Wholesale	11			5			—
Total Depreciation and Amortization Expense	$	368		$	313		$	233
Capital Expenditures
Terminalling and Transportation	$	205		$	188		$	193
Gathering and Processing	545			175			119
Wholesale	1			—			—
Total Capital Expenditures	$	751		$	363		$	312

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) The presentation of wholesale fuel sales was impacted by adoption of ASC 606 on January 1, 2018. Beginning January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements were netted.

December 31, 2018 |99

Notes to Consolidated Financial Statements

Total Identifiable Assets by Operating Segment (in millions)

	December 31,
	2018		2017 (a)
Identifiable Assets
Terminalling and Transportation	$	3,458	$	3,045
Gathering and Processing	6,488		6,006
Wholesale	255		342
Other	94		112
Total Identifiable Assets	$	10,295	$	9,505

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

Note 15 - Quarterly Financial Data (Unaudited)

	Quarters
	First		Second		Third		Fourth		Total Year
2018 (a)	(In millions, except per unit amounts)
Revenues	$	546	$	569	$	642	$	623	$	2,380
NGL expense (b)	48		45		73		40		206
Operating expenses	201		221		236		227		885
Operating income	177		180		215		224		796
Net earnings	131		132		166		171		600
Limited partners' interest in net earnings	125		138		160		161		584
Net earnings per limited partner unit (c):
Common - basic	$	0.59	$	0.63	$	0.68	$	0.66	$	2.57
Common - diluted	$	0.59	$	0.63	$	0.68	$	0.66	$	2.57
2017 (a)
Revenues	$	427	$	614	$	1,094	$	1,114	$	3,249
Cost of fuel and other (b)(d)	—		162		554		528		1,244
NGL expense (b)	59		56		64		86		265
Operating expenses	142		171		199		179		691
Operating income	131		146		147		179		603
Net earnings	73		90		90		53		306
Limited partners' interest in net earnings (c)	55		70		97		47		267
Net earnings per limited partner unit (c):
Common - basic	$	0.51	$	0.63	$	0.90	$	0.25	$	2.11
Common - diluted	$	0.51	$	0.63	$	0.90	$	0.25	$	2.11

(a) Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

(b) Excludes direct operating expenses incurred across our operating segments and depreciation and amortization expenses.

(c) The sum of four quarters may not equal annual results due to rounding or the quarterly number of units outstanding.

(d) Due to the adoption of ASC 606 effective January 1, 2018, the revenues and costs associated with our fuel purchase and supply arrangements for the year ended December 31, 2018 were netted. See Note 1 for further discussion.

100 |

Changes and Disagreements with Accountants, Controls and Procedures and Other Information

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance that the information that we are required to disclose in reports we file under the Exchange Act is accumulated and appropriately communicated to management. With the exception of the new Enterprise Resource Planning (“ERP”) implementation described below, there have been no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 principal executive officer and principal 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 principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of the end of the reporting period.

Management Report on Internal Control Over Financial Reporting

Management of Andeavor Logistics LP and its subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Exchange Act. The Partnership’s internal control system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2018, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013 framework). Based on such assessment, management concluded that as of December 31, 2018, the Partnership’s internal control over financial reporting is effective.

The independent registered public accounting firm of Ernst & Young LLP, as auditors of the Partnership’s consolidated financial statements, has issued an attestation report on the effectiveness of the Partnership’s internal control over financial reporting, included herein.

Item 9B. Other Information

None.

December 31, 2018 |101

Internal Control

Report of Independent Registered Public Accounting Firm

To the Unitholders of Andeavor Logistics LP and the Board of Directors of Tesoro Logistics GP, LLC

Opinion on Internal Control over Financial Reporting

We have audited Andeavor Logistics LP’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), (the COSO criteria). In our opinion, Andeavor Logistics LP (the “Partnership”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2018 and 2017, the related consolidated statements of operations, partners‘ equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes and our report dated February 28, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ ERNST & YOUNG LLP

San Antonio, Texas

February 28, 2019

102 |

Directors, Executive Officers and Corporate Governance

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Andeavor Logistics

Tesoro Logistics GP, LLC (“TLGP”), our general partner, is a wholly-owned subsidiary of Marathon Petroleum Corporation (“MPC”). Our general partner manages our operations and activities on our behalf through its officers and directors. Our common unitholders do not nominate candidates for, or vote for the election of, the directors of the general partner. The general partner is a limited liability company, and its directors are elected by its sole member, which is a wholly-owned subsidiary of MPC. The directors of our general partner hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. The executive officers of the general partner are appointed by, and serve at the discretion of, the Board.

References in this Part III to our “Board,” “directors,” or “officers” refer to the Board, directors and officers of our general partner.

Neither we, nor our subsidiaries, directly employ any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees who conduct our business are directly employed by affiliates of our general partner, but we sometimes refer to these individuals as our employees for ease of reference.

Directors and Executive Officers of Tesoro Logistics GP, LLC

The following table shows information for our directors, and executive and corporate officers.

Name	Age as of January 31, 2019	Position with Tesoro Logistics GP, LLC
Gary R. Heminger	65	Chairman of the Board of Directors and Chief Executive Officer
Pamela K.M. Beall	62	Director
Sigmund L. Cornelius	64	Director
Ruth I. Dreessen	62	Director
Gregory J. Goff	62	Director
Timothy T. Griffith	49	Director
Michael J. Hennigan	59	Director
James H. Lamanna	64	Director
Frank M. Semple	67	Director
Donald C. Templin	55	Director
Don J. Sorensen	51	President
Suzanne Gagle	53	General Counsel
Blane W. Peery	52	Vice President, Accounting and Systems Integration
D. Andrew Woodward	36	Vice President, Finance
Molly R. Benson (a)	52	Vice President, Chief Securities, Governance & Compliance Officer and Corporate Secretary
Kristina A. Kazarian (a)	36	Vice President, Investor Relations

(a) Corporate officer

Gary R. Heminger, 65, was appointed Chairman of the Board and Chief Executive Officer effective October 1, 2018. He has served as MPC’s Chairman of the Board since April 2016 and as its Chief Executive Officer since 2011. He was also MPC’s President from 2011 to 2017. Mr. Heminger has also served as Chairman of the Board and Chief Executive Officer of MPLX GP since June 2012. He began his career with Marathon in 1975 and has served in roles in finance and administration, auditing, marketing and commercial, and business development, including as President of Marathon Pipe Line Company; Manager, Business Development and Joint Interest of Marathon Oil Company; and Vice President and Senior Vice President, Business Development, Marathon Ashland Petroleum LLC. In 2001, he was named Executive Vice President, Supply, Transportation and Marketing, and was appointed President of Marathon Petroleum Company LLC and Executive Vice President-Downstream of Marathon Oil Corporation later that year. Mr. Heminger serves on the boards of directors and executive committees of the American Petroleum Institute (API) and the American Fuel & Petrochemicals Manufacturers (AFPM), and he is a member of the Oxford Institute for Energy Studies. He is a member of The Ohio State University Board of Trustees and past Chairman of the Tiffin University Board of Trustees. Mr. Heminger holds a bachelor’s degree in accounting from Tiffin University and a master’s

December 31, 2018 |103

Directors, Executive Officers and Corporate Governance

degree in business administration from the University of Dayton, and is a graduate of the Wharton School Advanced Management Program at the University of Pennsylvania.

Qualifications: Mr. Heminger brings to the Board energy industry expertise, extensive knowledge of all aspects of our business and a breadth of transactional experience. As our Chief Executive Officer, he leverages that expertise in advising on our strategic direction and apprising the Board on issues of significance to our industry and to us.

Other Public Company Directorships: Marathon Petroleum Corporation (since 2011); MPLX GP LLC (since 2012); Fifth Third Bancorp (since 2006); PPG Industries, Inc. (since 2017)

Pamela K.M. Beall, 62, was elected a member of the Board effective October 1, 2018. She has served as Executive Vice President and Chief Financial Officer of MPLX GP since 2016 and was elected to its Board in 2014. Ms. Beall began her career with Marathon in 1978 as an auditor, and then went on to serve as General Manager, Treasury Services, at USX Corporation; Vice President and Treasurer at NationsRent, Inc. and OHM Corporation, and as a member of the boards of directors of System One Services, Inc. and Boyle Engineering. Ms. Beall rejoined Marathon in 2002, serving in areas of increasing responsibility, including as Director, Corporate Affairs; Organizational Vice President, Business Development - Downstream; Vice President of Global Procurement, Marathon Oil Company; and Vice President of Products, Supply & Optimization. She served as MPC’s Vice President, Investor Relations and Government & Public Affairs from 2011 to 2014, when she was named President of MPLX GP. Ms. Beall was named Executive Vice President, Corporate Planning and Strategy of MPLX GP in 2016. She serves on the University of Findlay Board of Trustees and is a member of the Ohio Society of CPAs. Ms. Beall holds a bachelor’s degree in accounting from the University of Findlay and a master’s degree in business administration from Bowling Green State University, and has attended the Oxford Institute for Energy Studies. She is licensed as a certified public accountant in Ohio.

Qualifications: Ms. Beall brings to the Board extensive energy industry experience, specifically in the areas of finance and accounting, business development, risk management, procurement, investor relations and government affairs. In addition, her service as a senior executive in the environmental remediation and industrial product rental sectors equips her to contribute valuable insight into our business and operations.

Other Public Company Directorships: MPLX GP LLC (since 2014); National Retail Properties, Inc. (since 2016)

Sigmund L. Cornelius, 64, was elected a member of the Board effective January 2018. Mr. Cornelius has 38 years of experience in the energy industry and has served as the President and Chief Operating Officer of Freeport LNG, a private company that owns and operates an LNG import terminal, since April 2014. From 1980 to 2010, he worked for ConocoPhillips where he retired in 2010 as Senior Vice President, Finance and Chief Financial Officer after serving in a variety of executive management positions including: Senior Vice President, Planning, Strategy and Corporate Affairs; President, Exploration and Production-Lower 48; President, Global Gas; and President, Lower 48, Latin America & Midstream. Prior to that, he served in a variety of commercial, operational and administrative positions in the Midstream and Upstream business units in both domestic and international locations. Mr. Cornelius serves on the non-profit boards of Theatre Under the Stars, Upbring and Citizens for Animal Protection. Mr. Cornelius holds a bachelor’s degree in science from Iowa State University and master’s degrees in management from Purdue University and Stanford University.

Qualifications: Mr. Cornelius brings to the Board significant domestic and international executive experience in the energy industry, knowledge of the refining industry and extensive experience in the areas of corporate finance, accounting, strategic planning and risk oversight.

Other Public Company Directorships: Carbo Ceramics Inc. (since 2009); Western Refining Inc. (2012 to 2017); Parallel Energy Trust (2012 to 2015); Columbia Pipeline Group, Inc. (2015 to 2016); NiSource Inc. (2011 to 2015); USEC, Inc. (2011 to 2014); DCP Midstream GP, LLC (2007 to 2008)

Ruth I. Dreessen, 62, was elected a member of the Board effective January 2018. Ms. Dreessen has significant experience in the chemicals and energy business. From 2010 through 2018, she served as Managing Director of Lion Chemical Partners, LLC, a private equity firm focused on the chemicals business and related industries. Prior to joining Lion Chemical Partners, Ms. Dreessen served as the Executive Vice President and Chief Financial Officer of TPC Group Inc., a leading processor of C4 chemicals, from 2005 to 2010. Before joining TPC Group, Ms. Dreessen served as Senior Vice President, Chief Financial Officer and Director of Westlake Chemical Corporation, a producer of olefins and vinyls. She spent 21 years at JP Morgan Securities and predecessor companies, ultimately as a Managing Director of chemicals investment banking. Ms. Dreessen holds a bachelor’s degree in European history from New College of Florida and a master’s degree in international affairs from Columbia University.

Qualifications: Ms. Dreessen brings to the Board strong leadership skills developed while serving in several executive and board positions with publicly traded companies, as well as extensive financial experience.

Other Public Company Directorships: Gevo, Inc. (since 2012); Targa Resources LP (2013 to 2016); Versar, Inc. (2010 to 2014); Westlake Chemical Corporation (2004 to 2005); Georgia Gulf Corp. (2001 to 2003)

104 |

Directors, Executive Officers and Corporate Governance

Gregory J. Goff, 62, has served as a member of the Board since 2010. Upon the completion of MPC’s acquisition of Andeavor on October 1, 2018, Mr. Goff joined MPC as Executive Vice Chairman and as a member of the MPC and MPLX GP Boards of Directors. Prior to MPC’s acquisition of Andeavor, Mr. Goff served as Chief Executive Officer and President of Andeavor beginning in May 2010, and as its Chairman of the Board beginning in December 2014. He also served as our Chairman of the Board and Chief Executive Officer from December 2010 to October 2018. Prior to joining Andeavor, Mr. Goff served as Senior Vice President, Commercial for ConocoPhillips, an international, integrated energy company, from 2008 to 2010, and held a number of other positions at ConocoPhillips from 1981 to 2008, including Managing Director and CEO of Conoco JET Nordic; Chairman and Managing Director of Conoco Limited, a UK-based refining and marketing affiliate; President of ConocoPhillips Europe and Asia Pacific downstream operations; President of ConocoPhillips U.S. Lower 48 and Latin America exploration and production business; and President of ConocoPhillips’ specialty businesses and business development. Mr. Goff serves on the National Advisory Board of the University of Utah Business School and previously served as Chairman of the Board of AFPM. He holds a bachelor’s degree in science and a master’s degree in business administration from the University of Utah.

Qualifications: Mr. Goff brings to the Board a deep understanding of and unique perspective on our business, operations and market environment, as well as leadership, industry, strategic planning and operations experience.

Other Public Company Directorships: Marathon Petroleum Corporation (since 2018); MPLX GP LLC (since 2018); PolyOne Corporation (since 2011); Andeavor (2010 to 2018); Western Refining Logistics GP, LLC (2017); QEP Midstream Partners, LP (2014 to 2015); DCP Midstream LP (2008 to 2010)

Timothy T. Griffith, 49, was elected a member of the Board effective October 1, 2018. He has served as Senior Vice President and Chief Financial Officer of MPC since 2015. He has also served on the MPLX GP Board of Directors since March 2015. Mr. Griffith previously served as Vice President, Finance and Investor Relations, and Treasurer of MPC and MPLX GP from 2014 to 2015, as Vice President, Finance and Treasurer of MPC from 2011 to 2014 and in that same capacity for MPLX GP from 2012 to 2014. Prior to joining MPC, Mr. Griffith served as Vice President and Treasurer of Smurfit-Stone Container Corporation, where he had executive responsibility for the company’s investor interface and treasury operations, including capital structure, cash management, insurance and investment oversight. Mr. Griffith also served as Vice President and Treasurer of Cooper-Standard Automotive; as Assistant Treasurer of Lear Corporation; as the Capital Planning Officer for Comerica Incorporated and as a derivatives specialist with Citicorp Securities. Mr. Griffith holds a bachelor’s degree in economics from Michigan State University and a master’s degree in business administration from the University of Michigan, and has attended the Oxford Institute for Energy Studies. He is also a chartered financial analyst, a designation he has held since 1995.

Qualifications: Mr. Griffith brings to the Board extensive experience gained from a variety of roles in finance over the course of his career, including roles of increasing responsibility at several publicly traded and privately sponsored businesses and continuing with the management of the financial affairs of MPC and MPLX.

Other Public Company Directorships: MPLX GP LLC (since 2015)

Michael J. Hennigan, 59, was elected a member of the Board effective October 1, 2018. He has served on the MPLX GP Board of Directors since May 2017 and as MPLX GP President since June 2017. Prior to joining MPLX GP, Mr. Hennigan was President, Crude, NGL and Refined Products of the general partner of Energy Transfer Partners L.P., an energy service provider. Before that, from 2012 to 2017, he served as President and Chief Executive Officer of Sunoco Logistics Partners L.P., an oil and gas transportation, terminalling and storage company, where he was responsible for all operations and business activities, including setting the direction, strategy and vision for the company. Mr. Hennigan joined Sunoco Logistics as Vice President, Business Development in 2009, was named President and Chief Operating Officer in 2010 and was named President and Chief Executive Officer in 2012. He holds a bachelor’s degree in chemical engineering from Drexel University.

Qualifications: Mr. Hennigan brings to the Board a unique perspective and valued guidance gained from more than 35 years of industry experience, including as the president and chief executive officer of a successful growth-oriented master limited partnership.

Other Public Company Directorships: MPLX GP LLC (since 2017); Sunoco Partners LLC (2010 to 2017); Niska Gas Storage Partners LLC (2014 to 2016)

James H. Lamanna, 64, was elected a member of the Board effective March 2012. Since January 2011, Mr. Lamanna has served as President of Timeless Triumph LLC, a consulting firm providing advice to companies in the oil and gas industry regarding business plans; health, safety, security and environmental performance; operational efficiency; and plant reliability. From November 2014 to November 2015, he served as a member of the Board of Directors of North Atlantic Refining Limited, a refining and marketing business in Newfoundland, Canada. Since August 2016, Mr. Lamanna has also served as a member of the Board of Directors of Island Energy Services, a refining and marketing business in Hawaii. From 2003 to 2010, Mr. Lamanna held a variety of roles with BP P.L.C., a multinational oil and gas company, and its subsidiaries. During that time, he was President of BP Pipelines (North America) Inc. from April 2003 through August 2006; Senior Vice President of BP's U.S. Pipelines and Logistics operations from September 2006 through August 2009; and Vice President of Special Projects for BP's

December 31, 2018 |105

Directors, Executive Officers and Corporate Governance

U.S. Refining and Marketing operations from September 2009 through December 2010. Mr. Lamanna holds a bachelor’s degree in chemical engineering from the University of Virginia.

Qualifications:Mr. Lamanna brings to the Board extensive background in the energy and logistics industries, as well as important leadership and strategic experience he developed while serving in several executive positions.

Other Public Company Directorships: None within the last five years.

Frank M. Semple, 67, was elected a member of the Board effective October 1, 2018. He has served as a member of the MPLX GP board since 2015, and previously served as Vice Chairman of MPLX GP from 2015 until his retirement in 2016. Mr. Semple also served on the MPC Board of Directors from December 2015 to October 2018. Prior to joining MPLX GP, Mr. Semple served as President and Chief Executive Officer of MarkWest beginning in 2003, and as Chairman of the Board beginning in 2008. Prior to his time at MarkWest, he served 22 years with The Williams Companies, Inc. and WilTel Communications, including as Chief Operating Officer of WilTel Communications, Senior Vice President/General Manager of Williams Natural Gas Company, Vice President of Operations and Engineering for Northwest Pipeline Company and division manager for Williams Pipe Line Company. Prior to joining Williams, Mr. Semple served in the United States Navy. He holds a bachelor’s degree in mechanical engineering from the United States Naval Academy and has completed the Program for Management Development at Harvard Business School.

Qualifications: Mr. Semple brings to the Board proven leadership ability in managing a complex business and a deep understanding of the midstream sector gained from his experience as Chairman and Chief Executive Officer of MarkWest, as well as significant experience regarding operations, strategic planning, finance and corporate governance matters.

Other Public Company Directorships: MPLX GP LLC (since 2015); Marathon Petroleum Corporation (2015 to 2018); MarkWest Energy GP, L.L.C. (2003 to 2015)

Donald C. Templin, 55, was elected a member of the Board effective October 1, 2018. He has served as MPC’s President, Refining, Marketing and Supply since October 2018. He has also served on the MPLX GP Board of Directors since June 2012. Mr. Templin joined MPC as Senior Vice President and Chief Financial Officer in 2011 and was subsequently appointed as Vice President and Chief Financial Officer of MPLX GP in 2012, Executive Vice President, Supply, Transportation and Marketing of MPC in 2015, President of MPLX GP and Executive Vice President of MPC in 2016 and President of MPC in 2017. Prior to joining MPC, Mr. Templin was a managing partner of the audit practice of PricewaterhouseCoopers LLP with more than 25 years of providing auditing and advisory services to a wide variety of private, public and multinational companies. He is a member of the Grove City College Board of Trustees and past Chairman of the Downstream Committee of API. Mr. Templin is a graduate of Grove City College, a certified public accountant, a member of the American Institute of Certified Public Accountants and has attended the Oxford Institute for Energy Studies.

Qualifications: Mr. Templin brings to the Board direct insight into all aspects of our business, from an operational and commercial perspective, and in the areas of accounting, audit and financial management. His long and successful background in public accounting for energy sector clients affords him insight into public company financial reporting requirements and related matters.

Other Public Company Directorships: MPLX GP LLC (since 2012); Calgon Carbon Corporation (2013 to 2018)

Don J. Sorensen, 51, has served as our President since October 2018, having previously served as our Senior Vice President, Operations beginning in April 2016, and as Vice President, Operations beginning in January 2015. Mr. Sorensen also served as Senior Vice President, Logistics of a subsidiary of Andeavor from 2015 to 2018 and as Vice President, Integration from 2012 to 2015. Prior to that, Mr. Sorensen was Vice President of Andeavor’s Anacortes refinery from 2007 to 2012.

D. Andrew Woodward, 36, has served as our Vice President, Finance (principal financial officer) since October 2018, having previously served as Andeavor’s Senior Director of Finance and Investor Relations beginning in 2017, and Senior Director, Corporate Development beginning in 2015. Prior to joining Andeavor, Mr. Woodward served as Vice President, Midstream within the energy investment banking group of RBC Capital Markets, an investment banking firm.

Suzanne Gagle, 53, has served as our General Counsel since October 2018, and as the General Counsel of MPC since March 2016. She was also appointed General Counsel of MPLX GP in October 2017. Prior to her role as General Counsel, Ms. Gagle was MPC’s Assistant General Counsel, Litigation and Human Resources beginning in April 2011; Senior Group Counsel, Downstream Operations beginning in 2010; and Group Counsel, Litigation, beginning in 2003.

Blane W. Peery, 52, has served as our Vice President, Accounting and Systems Integration (principal accounting officer) since October 2018, having previously served as Vice President and Controller beginning in November 2016, and as Andeavor’s Vice President, Process Excellence and Chief Information Officer beginning in 2015. Prior to joining Andeavor, Mr. Peery served as Vice President, Global Business Services at Mylan N.V., a leading global pharmaceutical company. He also worked for Celanese Corporation, a global technology and specialty materials company, for over 20 years in roles with increasing responsibility, including as Vice President, Global Business Services from 2012 to 2014.

106 |

Directors, Executive Officers and Corporate Governance

Molly R. Benson, 52, has served as our Vice President, Chief Securities, Governance and Compliance Officer and Corporate Secretary since October 2018. She was also appointed Vice President, Chief Compliance Officer and Corporate Secretary of MPC and MPLX GP in March 2016, and Chief Securities and Governance Officer in June 2018. Previously, Ms. Benson was Assistant General Counsel, Corporate and Finance of MPC beginning in April 2012, and Group Counsel, Corporate and Finance of MPC beginning in 2011.

Kristina A. Kazarian, 36, has served as our Vice President, Investor Relations since October 2018, and as Vice President, Investor Relations of MPC and MPLX GP since April 2018. Prior to joining MPC, Ms. Kazarian was Managing Director and head of the MLP, Midstream and Refining Equity Research teams at Credit Suisse, a global investment bank and financial services company, beginning in September 2017. Previously she worked at Deutsche Bank, a global investment bank and financial services company, as Managing Director of MLP, Midstream and Natural Gas Equity Research beginning in September 2014, and as an analyst specializing on various energy industry subsectors with Fidelity Management & Research Company, a privately held investment manager, beginning in 2005.

Governance Framework

Our Governance Principles provide the functional framework of our Board. They address, among other things, the Board’s primary roles, responsibilities and oversight functions, director independence, committee composition, the process for director selection and director qualifications, director compensation and director retirement and resignation.

We have adopted a Code of Ethics for Senior Financial Officers that is specifically applicable to the Chairman and CEO, the Vice President, Finance, the Vice President, Accounting and Systems Integration and other persons performing similar functions, as well as to those designated as Senior Financial Officers by our Chairman and CEO or our Audit Committee. In addition, we have a Code of Business Conduct that applies to all of our directors, officers and employees. Copies of these documents are available on our website and printed copies are also available upon request to our Corporate Secretary. We will post on our website any amendments to, or waivers from, either of our Codes requiring disclosure under applicable rules within four business days following the date of the amendment or waiver.

Our Whistleblowing as to Accounting Matters Policy establishes procedures for the receipt, retention and treatment of complaints received by the Partnership regarding accounting, internal accounting controls or auditing matters, and the confidential, anonymous submission by employees or others of concerns regarding questionable accounting or auditing matters.

Copies of the Governance Principles, the Code of Ethics for Senior Financial Officers, the Code of Business Conduct and the Whistleblowing as to Accounting Matters Policy are available on our website at www.andeavorlogistics.com under the heading “Investors” and the subheading “Governance.”

Director Independence

The Board currently consists of ten directors. The NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on our Board. We are, however, required to have an audit committee comprised of at least three independent directors. The Board considered all relevant facts and circumstances including, without limitation, transactions between the director directly or organizations with which the director is affiliated and us, any service by the director on the board of a company with which we conduct business, and the frequency and dollar amounts associated with these transactions, and has determined that each of Messrs. Cornelius and Lamanna and Ms. Dreessen meets the independence standards in our Governance Principles, has no material relationship with us other than as a director, and satisfies the independence requirements of the NYSE and applicable SEC rules. Mr. Bromark, who retired from the Board effective September 27, 2018, also met these independence standards during his service on the Board in 2018.

Board Leadership Structure

Our Governance Principles provide the Board with the flexibility to determine from time to time the optimal leadership for the Board depending upon our particular needs and circumstances. The Board has determined that Mr. Heminger is in the best position at this time to serve as Chairman due to his extensive knowledge of our industry and business, as well as our continued relationship with MPC.

When the CEO is elected Chairman, the Board may appoint an independent director as “Lead Director” to provide independent director oversight and preside over executive sessions of the Board or other Board meetings when the Chairman is absent. While the Board has not elected a Lead Director at this time, pursuant to the Governance Principles, the Chair of the Audit Committee presides over executive sessions of the non-management directors. The Board believes that this leadership structure is in the best interests of our unitholders and us at this time because it strikes an effective balance between management and independent director participation in the Board process.

December 31, 2018 |107

Directors, Executive Officers and Corporate Governance

Committees of the Board

Our Board has a standing Audit Committee and Conflicts Committee, each of which operates under a written charter, and may have such other committees as the Board shall determine from time to time. The Audit Committee charter is available on our website at www.andeavorlogistics.com under the heading “Investors” and the subheading “Governance.” Because we are a limited partnership, we are not required to have a compensation committee or a nominating/corporate governance committee.

Audit Committee

Our Audit Committee assists the Board in fulfilling its responsibility to our unitholders and us relating to its oversight of management and its auditors concerning:

• corporate accounting and financial reporting practices;

• the quality and integrity of our financial statements;

• the independent auditor’s qualifications, independence and performance;

• the performance of our internal audit function; and

• our systems of disclosure controls and procedures and internal controls over financial reporting.

Our Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our Audit Committee also is responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to our Audit Committee.

The Audit Committee is comprised of Ms. Dreessen (Chair), and Messrs. Cornelius and Lamanna. The Board has determined that each member of the Audit Committee meets the independence requirements of the NYSE and the SEC, as applicable, and that each is financially literate. The Board also has determined that each of Mr. Cornelius and Ms. Dreessen qualifies as an “audit committee financial expert,” as defined by SEC rules, based on the attributes, education and experience further described in their biographies under “Directors and Executive Officers of Tesoro Logistics GP, LLC,” above.

Audit Committee Report

The Audit Committee has reviewed and discussed the Partnership’s audited financial statements and its report on internal control over financial reporting for 2018 with the management of Tesoro Logistics GP, LLC, the Partnership’s general partner. The Audit Committee discussed with the independent auditors, Ernst & Young LLP, the matters required to be discussed by the Public Company Accounting Oversight Board’s standard, Auditing Standard No. 1301. The Committee has received the written disclosures and the letter from Ernst & Young LLP required by the applicable requirements of the Public Company Accounting Oversight Board for independent auditor communications with audit committees concerning independence and has discussed with Ernst & Young LLP its independence. Based on the review and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements and the report on internal control over financial reporting for Andeavor Logistics LP be included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018, for filing with the SEC.

Ruth I. Dreessen, Chair

Sigmund L. Cornelius

James H. Lamanna

Conflicts Committee

Our Conflicts Committee reviews specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. Any matters approved by our Conflicts Committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe our unitholders or us. The members of our Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the SEC to serve on an audit committee. In addition, the members of our Conflicts Committee may not own any interest in our general partner or any interest in us, our subsidiaries or our affiliates other than common units or awards under our incentive compensation plan.

Our Conflicts Committee is comprised of Messrs. Cornelius (Chair) and Lamanna and Ms. Dreessen. The Board has determined that each member of the Conflicts Committee meets the independence requirements of the NYSE and the SEC, as applicable.

108 |

Directors, Executive Officers and Corporate Governance

Communicating with the Board

All interested parties, including unitholders, may communicate directly with our independent directors by writing to:

Board of Directors (non-management members)

c/o Corporate Secretary, Tesoro Logistics GP, LLC

200 East Hardin Street

Findlay, Ohio 45840

Interested parties may communicate with the Chairs of our Audit Committee or Conflicts Committee by sending an email to:

ANDXAuditChair@marathonpetroleum.com

ANDXConflictsChair@marathonpetroleum.com

Interested parties may communicate with the independent directors, individually or as a group, by sending an e-mail to:

ANDXNon-ManageDirectors@marathonpetroleum.com

The Corporate Secretary will forward to the directors all communications that, in her judgment, are appropriate for consideration by the directors. Examples of communications that would not be considered appropriate include commercial solicitations and matters not relevant to the Partnership’s affairs.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our directors, executive officers, and holders of more than 10% of a registered class of our equity securities to file with the SEC initial reports of beneficial ownership and reports of changes in beneficial ownership of our equity securities. Based solely on our review of the reporting forms and written representations provided by the individuals required to file reports, we believe that during the year ended December 31, 2018, our directors, executive officers and greater-than-10% beneficial holders filed the required reports on a timely basis under Section 16(a).

Item 11. Executive Compensation

Compensation Discussion and Analysis

This compensation discussion and analysis ("CD&A") describes the material components of the executive compensation program for our named executive officers (our “NEOs”). We also provide an overview of our compensation philosophy and objectives and explain how and why 2018 compensation decisions were made. We recommend that this section be read in conjunction with the tables and related disclosures in the “Executive Compensation Tables” section of this Item 11.

Our general partner, Tesoro Logistics GP, LLC, manages our operations and activities on our behalf through its officers and directors. Prior to October 1, 2018, our general partner was a wholly-owned subsidiary of Andeavor. On October 1, 2018, MPC completed its acquisition of Andeavor in accordance with the Agreement and Plan of Merger, dated as of April 29, 2018, as amended, under which MPC acquired Andeavor. As a result of the MPC Merger, our general partner became a wholly-owned subsidiary of MPC.

Most compensation decisions for our NEOs for 2018 were made prior to the MPC Merger, and thus were made by Andeavor’s compensation committee. Unless the context otherwise requires, references in this Item 11 to our “Sponsor” refer to Andeavor for events occurring through September 30, 2018, and to MPC for events occurring on or after October 1, 2018. References in this Item 11 to our “Board,” “directors,” “officers,” “named executive officers,” “NEOs,” “Chairman,” “compensation program,” or similar terms refer to the Board, directors, officers, named executive officers, Chairman and compensation program of our general partner or our Sponsor, as applicable.

Named Executive Officers

Our NEOs for 2018 were:

• Gary Heminger, Chief Executive Officer and Chairman of the Board;

• D. Andrew Woodward, Vice President, Finance;

• Don J. Sorensen, President;

• Gregory J. Goff, Former Chief Executive Officer and Chairman of the Board;

• Steven M. Sterin, Former President and Chief Financial Officer; and

• Kim K. W. Rucker, Former Executive Vice President and General Counsel.

December 31, 2018 |109

Executive Compensation

Messrs. Heminger and Woodward were elected to their current positions on October 1, 2018, in connection with the MPC Merger. Mr. Sorensen was elected to his current position on October 1, 2018, having previously served as our Senior Vice President, Operations. Messrs. Goff and Sterin and Ms. Rucker resigned their positions with us in October 2018, in connection with the MPC Merger. Mr. Goff remains employed with MPC.

Compensation Decisions and Allocation

Under the terms of the Amended Omnibus Agreement, we pay an annual administrative fee to our Sponsor of $17 million for the provision of general and administrative services for our benefit. The general and administrative services covered by this fee include, without limitation, information technology services; legal services; health, safety and environmental services; human resources services; executive management services of our Sponsor’s employees who devote less than a majority of their business time to our business and affairs; financial and administrative services (including treasury and accounting); and insurance coverage under our Sponsor’s insurance policies. None of the services covered by the administrative fee are assigned any particular individual value.

As our NEOs are employed by our Sponsor, their compensation is primarily determined by our Sponsor. However, our Board does review certain elements of their compensation and approves awards to them under the Andeavor Logistics LP 2011 Long-Term Incentive Plan (as amended and restated, the “LTIP”). These compensation decisions generally are delegated to a committee of the Board comprised of our Chairman and the independent directors (the “ANDX Committee”). While the ANDX Committee makes awards to our NEOs under the LTIP, it does so only following the recommendation of our Sponsor’s compensation committee.

Prior to the MPC Merger, the ANDX Committee was comprised of Messrs. Goff, Bromark, Cornelius and Lamanna and Ms. Dreessen. Following the MPC Merger, the ANDX Committee was comprised of Messrs. Heminger, Cornelius and Lamanna and Ms. Dreessen.

Compensation Disclosure

Mr. Heminger was elected our Chairman and CEO effective October 1, 2018, in connection with the MPC Merger. Since that time, he has served as an executive officer for both MPC and us. Although he provided services to both MPC and us during that time, no portion of the administrative fee was specifically allocated to services he provided us. Decisions related to his compensation were made by MPC’s compensation committee. Accordingly, this CD&A and the accompanying tables do not reflect any compensation received by Mr. Heminger from us or on our behalf. Information with respect to compensation decisions for Mr. Heminger can be found in MPC’s annual proxy statement.

Until their resignations in October 2018 in connection with the MPC Merger, Messrs. Goff and Sterin and Ms. Rucker served as executive officers for both Andeavor and us. Although they provided services to both Andeavor and us, no portion of the administrative fee is specifically allocated to services they provided us. Decisions related to their compensation were made by Andeavor’s compensation committee. Other than equity awards we granted them, which are described further under “Elements of Compensation—Long-Term Incentive Compensation,” no portion of their compensation expense or other benefits for 2018 was allocated to us. Accordingly, this CD&A and the accompanying tables reflect only the equity awards we granted them. Information with respect to other compensation decisions for Mr. Goff, who is currently employed by MPC, can be found in MPC’s annual proxy statement.

In addition to the administrative fee discussed above, we reimburse our Sponsor for certain expenses incurred on our behalf, allocated to us pursuant to our Sponsor’s allocation methodology, including:

• 100% of Mr. Woodward’s compensation expenses for the period from October 1, 2018 (the date he was elected as our Vice President, Finance) through December 31, 2018; and

• 90% of Mr. Sorensen’s compensation expenses for 2018.

Accordingly, unless otherwise indicated, this CD&A and the accompanying tables reflect the portions of Messrs. Woodward’s and Sorensen’s compensation that have been allocated to us.

Compensation Consultants

Our Board does not have a compensation committee, and neither it nor the ANDX Committee has hired its own compensation consultant. Andeavor's compensation committee engaged BDO USA, LLP, and MPC’s compensation committee engaged Pay Governance LLC, to provide compensation consulting services and benchmarking information. This information was shared with our Board for use in making certain compensation decisions for our NEOs.

110 |

Executive Compensation

Elements of Compensation

Our executive compensation programs have been designed to create a pay for performance culture. In general, our executive compensation programs are comprised of a mix of fixed and variable cash and equity-based pay with a significant portion of actual total compensation dependent on meeting financial and operational objectives. Our executive officers generally receive their maximum reward opportunity only if we perform exceptionally well, and our unitholders benefit from that performance.

Compensation Element	Objective	Key Features	Performance-Based / At Risk?
Base Salary	Reflects executive responsibilities, job characteristics, seniority, experience and skill set Designed to be competitive with those of comparable companies with which we compete for talent	Reviewed annually and subject to adjustment based on market factors, individual performance, experience and leadership	NO
Annual Cash Incentive Compensation Program	Rewards executives’ contributions to the achievement of predetermined Andeavor corporate, business unit and individual goals	Establishes performance measures that best align performance relative to meeting financial and safety goals, ultimately driving unitholder value	YES - Pays out only based on achievement of established measurable goals Does not pay out if established threshold goals are not achieved
Long-Term Equity Awards in the form of Performance Phantom Units	Correlates executives’ pay with relative increases (as compared to a peer group) in unitholder value over a three-year period	In periods of low relative performance, executives realize little or no value In periods of high relative performance, executives may realize substantial value	YES - Pays out only based on increased relative unitholder value May not vest depending upon unitholder return

The ANDX Committee generally reviewed each executive’s total compensation for overall alignment with our compensation peer group and our compensation philosophy. However, the appropriate level for each component of total compensation was not determined exclusively based on comparative analysis against our compensation peer group. The ANDX Committee considered other factors, which included internal pay equity and consistency and the executive’s job responsibilities, management experience, individual contributions, number of years in his or her position and recent compensation adjustments, as well as other relevant considerations (with no particular weighting assigned to any of these factors).

In general, our emphasis on variable, or at risk, components of incentive pay results in actual compensation ranging above or below targeted amounts based on achievement of the objectives established in our annual cash incentive and long-term incentive plans and changes in the value of our units. While the ANDX Committee assessed each compensation component separately, the aggregate total direct compensation was generally considered in the context of the overall pay determination. Our strategy also includes ongoing evaluation and adaptation, as necessary, of our compensation programs to help ensure continued alignment between company performance and pay.

2018 Base Salary

Base salaries for our NEOs who devote a majority of their time to our business generally were reviewed by the ANDX Committee. As part of its annual review of compensation in February 2018, the ANDX Committee approved an increase in Mr. Sorensen’s base salary to $456,300 from $424,400 to bring his base salary to a more competitive level based on the market data. Mr. Woodward’s base salary increased to $229,871 from $220,500 as part of Andeavor’s annual merit program to maintain market competitiveness. As Mr. Woodward was not yet an officer of ANDX, this increase was not reviewed by the ANDX Committee.

Andeavor’s 2018 Incentive Compensation Program

The ANDX Committee believes that annual cash-based incentives drive achievement of annual performance goals and objectives, which create additional unitholder value. In February 2018, Andeavor’s compensation committee approved the terms of the 2018 Incentive Compensation Program (the “ICP”) for Andeavor’s employees, including our NEOs (other than Mr. Heminger, who joined us in the fourth quarter of 2018 and did not participate in the ICP).

December 31, 2018 |111

Executive Compensation

Andeavor’s ICP used a mix of objectives designed to focus management on key areas of performance and allowed for cascading corporate goals down the Andeavor organization from corporate through business units to individuals. Andeavor’s ICP provided all employees under the program, including our participating NEOs, with the same upward and downward bonus opportunity (0% below threshold; 50% at threshold; 100% at target; and 200% at maximum; with interpolation between levels), subject to adjustment based on individual performance. The calculation for determining the total payout to each participating NEO was:

[ Bonus Eligible Earnings x Target Bonus % x % Overall Company Performance Achieved ] +/- Individual Performance Adjustment ^(a) = Final Award

(a) Calculated as a percentage of the individual target bonus opportunity (bonus eligible earnings multiplied by target bonus percentage).

Company performance under the 2018 ICP was determined by measuring Andeavor’s overall corporate performance, as assessed by MPC’s compensation committee, against the performance measures established by Andeavor’s compensation committee. The table below provides the goals for each measure, target weighting and performance achieved in 2018 ($ in millions):

Performance Measure	Threshold (50% Payout)		Target (100% Payout)		Maximum (200% Payout)		Weighting (%)	Performance Achieved (a) (%)
Margin-neutral EBITDA (b)	$	2,762	$	3,249	$	3,573	50	200
Growth, Productivity and Synergy Improvements (c)	$	437	$	486	$	559	20	200
Cost Management (d)	$	3,961	$	3,772	$	3,583	15	106
Process Safety Management (e)	0.18		0.16		0.14		5	—
Environmental (e)	33		28		25		5	88
Personal Safety (f)	0.73		0.57		0.51		5	84
							Total	165

(a) MPC’s compensation committee had the discretion to adjust Andeavor’s performance results to take into account unplanned or unanticipated business decisions or events that are outside of management’s control, unusual or non-recurring items, and other factors, to determine the total amount, if any, payable under the 2018 ICP. In calculating Andeavor’s performance under each measure, MPC’s compensation committee considered the impact of the MPC Merger and determined to adjust Andeavor’s performance under each measure to consider Andeavor’s performance for the period from January 1, 2018 through September 30, 2018, prior to its acquisition on October 1, 2018, rather than for the full 2018 fiscal year.

(b) Achievement of U.S. GAAP-based net earnings before interest, income taxes, depreciation and amortization, measured on a margin neutral basis by excluding fluctuations in commodity prices (and thereby fluctuations in margins) over which management has little influence.

(c) Targeted improvements from growth initiatives, productivity with existing assets and synergies from acquisitions to create value, including growth from income-generating capital improvements, margin improvement initiatives, organic growth initiatives and other smaller projects.

(d) Measurement of operating expenditures and administrative expenses less certain adjustments. The cost metric excludes refining energy costs, annual incentive compensation costs, stock-based compensation expense, non-controllable expenses for post-retirement employee benefits (pension, medical, life insurance) and insurance costs (property, casualty and liability).

(e) Targeted improvement in the number of incidents over the average for the past three years. Threshold is set at the three-year average.

(f) Targeted improvement in the number of recordable personal safety incidents over the average for the past three years. Threshold is set at the three-year average.

For the calculation of both the EBITDA and cost management measures, MPC’s compensation committee had the discretion to take into consideration special items, including decisions that had a material impact on Andeavor’s results compared to budget, unusual items and non-recurring items. In calculating the EBITDA measure results, MPC’s compensation committee made adjustments to account for acquisition and transaction-related costs that were not included in the original targets and bonus related cost increases and decreases relative to the original target. In calculating the cost management measure results, MPC’s compensation committee made adjustments to account for an accounting classification change that moved logistics related service costs from Cost of Sales to Operating Expense after targets were set.

The 2018 ICP provided that Messrs. Woodward’s and Sorensen’s payouts could be adjusted above or below the amount determined by Andeavor’s overall corporate performance based on an assessment of each NEO’s overall performance, taking into account business unit performance and individual performance. For Mr. Woodward, senior management considered his new role as principal financial officer and his leadership in the integration of the companies’ financial systems following the MPC Merger. For Mr. Sorensen, MPC’s compensation committee considered his contributions to our performance and growth, including among other things, his leadership of our business following the MPC Merger.

112 |

Executive Compensation

Taking into consideration Andeavor’s overall corporate performance, adjusted based on each NEO’s individual performance, the 2018 annual bonus payouts approved were:

Name	Bonus Eligible Earnings ($) (a)	Target Bonus as a % of Earnings	Target Bonus ($)	Final Award as a % of Target	Final Award ($)
Woodward (b)	228,069	35	79,824	180	143,684
Sorensen (c)	450,165	90	405,149	173	700,000

(a) Bonus eligible earningsis based on salary earned during the 2018 calendar year.

(b) Reflects Mr. Woodward’s full ICP payout for 2018. As discussed above, we have been allocated 100% of Mr. Woodward’s cash compensation attributable to the period from October 1, 2018 through December 31, 2018.

(c) Reflects Mr. Sorensen’s full ICP payout for 2018. As discussed above, 90% of Mr. Sorensen’s cash compensation was allocated to us for 2018.

Long-Term Incentive Compensation

To promote alignment of interests between our senior leaders and unitholders, our general partner adopted the LTIP primarily for the benefit of our and our affiliates’ (including our Sponsor’s) eligible officers, employees and directors who perform services for us. Awards have generally been made on an annual basis to reward service or performance by our non-employee directors, executive officers and key employees.

2018 Equity Awards

Following a recommendation by Andeavor’s compensation committee, in the first quarter of 2018, the ANDX Committee granted performance phantom unit awards under the LTIP to certain of our NEOs. The number of units granted was consistent with Andeavor’s compensation structure, which granted executive officers and key employees an aggregate target value of long-term incentive awards under both our LTIP and Andeavor’s long-term incentive programs. For Messrs. Goff and Sterin and

Ms. Rucker, this value was comprised 25% of our performance phantom units and 75% of Andeavor equity awards. For

Mr. Sorensen, this value was comprised 50% of our performance phantom units and 50% of Andeavor equity awards. Andeavor’s compensation committee and the ANDX Committee believed these allocations were appropriate given each executive’s respective responsibilities. Messrs. Heminger and Woodward, who did not become our officers until October 1, 2018, did not receive equity awards from us in 2018. See the “2018 Grants of Plan-Based Awards” table below for the number of performance phantom units granted to our NEOs in 2018.

Each performance phantom unit award was scheduled to vest based on the achievement of relative total unitholder return over a performance period from February 16, 2018 through February 16, 2021, as compared to the performance of a peer group of companies. The peer companies consisted of: Alerian MLP ETF; Buckeye Partners, L.P.; DCP Midstream Partners, LP; Enbridge Energy Partners, L.P.; EnLink Midstream Partners, LP; EQT Midstream Partners, LP; Genesis Energy L.P.; Holly Energy Partners L.P.; Magellan Midstream Partners L.P.; MPLX L.P.; NuStar Energy L.P.; and Western Gas Partners, LP. These companies were selected based on our view that key stakeholders compare our business results and relative performance with these particular entities. The payout was designed to range from 0% to 200% of the units vesting, as follows:

Relative Total Unitholder Return	Payout as a % of Target
75th percentile and above	200%
50th percentile	100%
30th percentile	60%
Below 30th percentile	—

The performance phantom units granted to our participating NEOs in 2018 included tandem distribution equivalent rights (“DERs”) to receive an amount equal to all or a portion of the cash distributions made on units while they remain unvested.

Equity Award Payouts in 2018

As a result of the MPC Merger, the performance periods applicable to all then-outstanding performance phantom units previously granted to our NEOs ended as of October 1, 2018. All performance units held by our NEOs were converted to time-based phantom units based on the greater of target or actual performance of the original awards, as certified by our third-party consultant, Aon plc, and approved by the Board on October 16, 2018. The following table shows the performance period and results for each award.

Performance Unit Grant Date	Original Performance Period	Final Performance Period	Actual TUR (%)	Relative Total Unitholder Return	Payout (% of Target)	DER Value/Unit ($)
2/9/2016	1/1/2016—12/31/2018	1/1/2016—10/1/2018	8.22	72nd percentile	145.44	9.3782
2/16/2017	2/16/2017—2/16/2020	2/16/2017—10/1/2018	(0.67)	72nd percentile	145.44	5.9412
2/16/2018	2/16/2018—2/16/2021	2/16/2018—10/1/2018	0.60	63rd percentile	154.52	2.0450

December 31, 2018 |113

Executive Compensation

As a result, the Board approved the following awards to our NEOs:

	Target Number of Performance Units			Number of Units Awarded
Name	2016	2017	2018	2016	2017	2018
Sorensen	5,056	4,398	6,476	7,354	6,397	10,007
Goff	44,238	38,054	49,580	64,340	55,346	76,612
Sterin	8,974	7,780	10,523	13,052	11,316	16,261
Rucker	6,741	5,920	8,095	9,805	8,611	12,509

The vesting terms of the phantom units held by Messrs. Sorensen and Goff, who remained employed by MPC following the MPC Merger, remain unchanged from the original awards. Phantom units received by Mr. Sterin and Ms. Rucker, whose employment was terminated in October 2018 in connection with the MPC Merger, vested on an accelerated basis based on the certified performance results. Phantom units received by our participating NEOs pursuant to the performance certification and conversion are shown in the “Option Exercises and Units Vested in 2018” table below.

Other Benefits

We do not sponsor any benefit plans, programs or policies such as healthcare, life insurance, income protection or retirement benefits for our NEOs, and we generally do not provide perquisites. However, those types of benefits are generally provided to our NEOs by our Sponsor. Our Sponsor makes all determinations with respect to such benefits without input from our Board or us. Our Sponsor bears the full cost of these programs, and no portion is charged back to us. We have summarized the material elements of these programs below.

Retirement Benefits

Retirement benefits provided to our NEOs are designed by our Sponsor to be consistent in value and aligned with benefits offered by the other companies with which our Sponsor competes for talent. Benefits payable under our Sponsor’s qualified and nonqualified plans are described in more detail in “Post-Employment Benefits” and “Nonqualified Deferred Compensation.”

Severance Benefits

We have not entered into employment agreements with our NEOs. However, certain of our NEOs participate in Andeavor’s Executive Severance and Change-in-Control Plan, which Andeavor provided to help attract and retain talented individuals for these important positions. In addition, each NEO participates in the severance policy maintained for our Sponsor’s employees. These change of control benefits are described in more detail in “2018 Potential Payments Upon Termination or Change in Control.”

Perquisites

To promote consistency with our Sponsor’s overall practices and our compensation philosophy, and to adopt a best practice compensation design, we generally do not provide perquisites to our executive officers. Our Sponsor provides health and welfare benefits to employees, including our NEOs.

Compensation Governance

Prohibition on Derivatives and Hedging

We prohibit hedging transactions related to our units, and pledging or creating security interests in our units, including units in excess of a unit ownership guideline requirement. This ensures that our executive officers, including our NEOs, bear the full risk of ANDX LP common unit ownership. 

Recoupment/Clawback Policy

In 2012, our Board adopted a compensation recoupment, or clawback, policy providing that, in the event of a material restatement of our financial results due to misconduct, our independent directors will review all annual incentive payments and long-term incentive compensation awards made to any individual then serving as our vice president or above, or as our company controller or other officer with substantial responsibility for accounting matters, on the basis of having met or exceeded specific performance targets in grants or awards made after 2012, which occur during the 24-month period prior to restatement. If such compensation would have been lower had it been calculated based on such restated results, our independent directors will, to the extent permitted by governing law, seek to recoup for our benefit such compensation to any of the officers described above whose misconduct caused or significantly contributed to the material restatement, as determined by the independent directors. Notwithstanding the foregoing, with respect to any such officer who serves as an executive officer of our Sponsor, thereby requiring that such officer’s awards under the LTIP be granted only following a recommendation made by our Sponsor’s board of directors or compensation committee, our independent directors will only seek such recoupment of benefits after consultation with our Sponsor’s board of directors or compensation committee.

114 |

Executive Compensation

Compensation-Based Risk Assessment

The ANDX Committee reviews our policies and practices in compensating our service providers (including both executive officers and non-executives, if any) as they relate to our risk management profile. The ANDX Committee completed its review of our 2018 programs in February 2019, and concluded that any risks arising from our compensation policies and practices were not reasonably likely to have a material adverse effect on our financial statements.

Compensation Committee Interlocks and Insider Participation

As discussed above under “Compensation Decisions and Allocation,” certain executive officer compensation decisions are made by the ANDX Committee, comprised of our Chairman and independent directors. Prior to the MPC Merger, Mr. Goff served as both our Chairman and CEO and as an executive officer and director of Andeavor. Following the MPC Merger, Mr. Heminger serves as both our Chairman and CEO and as an executive officer and director of MPC. During 2018, none of our other executive officers served as a member of a compensation committee or board of directors of another entity that has an executive officer serving as an independent director on our Board. Please see Item 13—Certain Relationships and Related Transactions, and Director Independence for more information about relationships between our Sponsor and us.

Compensation Committee Report

Our Chairman and independent directors have reviewed and discussed the Compensation Discussion and Analysis for 2018 with management and, based on such review and discussions, recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

Gary R. Heminger, Chairman

Sigmund L. Cornelius

Ruth I. Dreessen

James H. Lamanna

December 31, 2018 |115

Executive Compensation

Executive Compensation Tables

2018 Summary Compensation Table

The following table provides information regarding compensation for our 2018 NEOs for the years shown. As discussed above under “Compensation Decisions and Allocation,” our Sponsor allocates a portion of the compensation expenses for Messrs. Woodward and Sorensen to us. Amounts for 2018 in the “Salary,” “Bonus,” “Change in Pension Value and Nonqualified Deferred Compensation Earnings” and “All Other Compensation” columns reflect the portion allocated to us: (i) for Mr. Woodward, 100% for the period from October 1, 2018 through December 31, 2018; and (ii) for Mr. Sorensen, 90% for 2018. No portion of these compensation items for the other NEOs was allocated or attributable to us.

Name and Principal Position	Year	Salary ($)	Unit Awards ($) (a)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (b)	All Other Compensation ($) (c)	Total ($)
Gary R. Heminger Chief Executive Officer and Chairman of the Board	2018	—	—	—	—	—	—
D. Andrew Woodward Vice President, Finance (Principal Financial Officer)	2018	58,352	—	35,921	2,728	4,937	101,938
Don J. Sorensen President	2018	407,280	400,023	630,000	—	99,480	1,536,783
	2017	380,215	325,056	275,855	401,155	37,771	1,420,052
	2016	366,404	243,345	297,281	269,017	387,525	1,563,572
Gregory J. Goff Former Chief Executive Officer and Chairman of the Board	2018	—	3,062,557	—	—	—	3,062,557
	2017	—	2,812,571	—	—	—	2,812,571
	2016	—	2,129,175	—	—	—	2,129,175
Steven M. Sterin Former President and Chief Financial Officer	2018	—	650,006	—	—	—	650,006
	2017	—	575,020	—	—	—	575,020
	2016	—	431,919	—	—	—	431,919
Kim K.W. Rucker Former Executive Vice President and General Counsel	2018	—	500,028	—	—	—	500,028
	2017	—	437,547	—	—	—	437,547
	2016	—	324,444	—	—	—	324,444

(a) Amounts for 2018 reflect the aggregate grant date fair value of performance phantom units granted during the year, calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification 718, Compensation-Stock Compensation (“FASB ASC Topic 718”). See Note 1 to our consolidated financial statements in Item 8 for assumptions used in this calculation. The aggregate grant date fair value of the performance phantom units granted in 2018, assuming the highest level of performance is achieved, would be as follows: Mr. Sorensen, $800,045; Mr. Goff, $6,125,113; Mr. Sterin, $1,300,011; and Ms. Rucker, $1,000,056. Amounts do not include Andeavor’s equity awards, which are not allocated to us.

(b) Amounts reflect the change in pension value during the fiscal year. The amount for Sorensen was a decrease of $40,085, therefore $0 is reflected in the table.

(c) Amounts for 2018 include:

◦ Andeavor 401(k) Plan Contributions: Andeavor provided matching contributions dollar-for-dollar up to 6% of eligible earnings for all employees who participated in the Andeavor 401(k) Plan. The portion of the matching contributions allocated to us for 2018 was $3,421 for Mr. Woodward and $14,850 for Mr. Sorensen. In addition, Andeavor provides a profit sharing contribution to the 401(k) Plan. This discretionary contribution, calculated as a percentage of employee’s base pay based on a pre-determined target for the calendar year, can range from 0% to 4% based on actual performance. The profit sharing contributions allocated to us for 2018 were $1,375 for Mr. Woodward and $4,950 for Mr. Sorensen.

◦ Andeavor Executive Deferred Compensation Contributions: Andeavor matched participants’ base salary contributions dollar-for-dollar up to 4% of eligible earnings above the Internal Revenue Code annual compensation limit ($275,000 for 2018). The portion of the matching contributions allocated to us for 2018 was $26,010 for Mr. Sorensen. Also, the Plan credited a discretionary profit sharing contribution in an amount up to 2% of each participant’s Plan-considered compensation. The profit sharing contributions allocated to us for 2018 were $141 for Mr. Woodward and $8,670 for Mr. Sorensen.

◦ Long-Term Incentive Award Amendment: Andeavor entered into an agreement with Mr. Sorensen that extended and strengthened certain non-competition provisions in his long-term incentive award agreements. The portion of the payment he received as consideration for these additional obligations that was allocated to us was $45,000.

116 |

Executive Compensation

2018 Grants of Plan-Based Awards

The following table provides information regarding all plan-based awards, including cash-based incentive awards and ANDX equity-based awards, granted to our NEOs in 2018.

Name	Award Type	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards ($) (a)			Estimated Future Payouts Under Equity Incentive Plan Awards ($) (b)			Grant Date Fair Value of Unit Awards ($) (c)
			Threshold	Target	Maximum	Threshold	Target	Maximum
Woodward	Annual Incentive	N/A	9,978	19,956	39,912	—	—	—	—
Sorensen	Annual Incentive	N/A	182,317	364,634	729,268	—	—	—	—
	Phantom Units	2/16/2018	—	—	—	3,886	6,476	12,952	400,023
Goff	Phantom Units	2/16/2018	—	—	—	29,748	49,580	99,160	3,062,557
Sterin	Phantom Units	2/16/2018	—	—	—	6,314	10,523	21,046	650,006
Rucker	Phantom Units	2/16/2018	—	—	—	4,857	8,095	16,190	500,028

(a) “Threshold” represents the minimum payout for the performance metrics under the ICP assuming that the minimum level of performance is attained. “Target” represents the amount payable if the performance metrics are reached. “Maximum” represents the maximum payout assuming that the maximum level of performance is attained. See “Elements of Compensation— Andeavor’s 2018 Incentive Compensation Program” for more information about awards under the ICP. Amounts in these columns reflect the range of compensation expense allocated to us by our Sponsor with respect to awards under Andeavor’s ICP: Mr. Woodward, 100% for the period from October 1, 2018 through December 31, 2018; Mr. Sorensen, 90% for 2018. These columns do not show the ICP range for Messrs. Goff and Sterin or Ms. Rucker, as no portion of their ICP payout was allocated to us.

(b) Amounts show the number of performance phantom units granted during 2018 under our LTIP as described under “Elements of Compensation—Long-Term Incentive Compensation.” The performance period for this award ended on October 1, 2018 as a result of the MPC Merger. The final performance factor of 154.52% was applied to the target share amounts resulting in the following number of units being earned: Mr. Sorensen, 10,007; Mr. Goff, 76,612; Mr. Sterin, 16,261; and Ms. Rucker, 12,509.

(c) Amounts reflect the grant date fair value calculated in accordance with FASB ASC Topic 718. See Note 1 to our consolidated financial statements in Item 8 for assumptions used in this calculation.

December 31, 2018 |117

Executive Compensation

Outstanding Equity Awards at 2018 Fiscal Year-End

The following table provides information regarding the outstanding ANDX equity awards held by our NEOs as of December 31, 2018.

	Equity Awards (a)
Name	Grant Date (b)	Number of Units That Have Not Vested (c)	Market Value of Units That Have Not Vested ($) (d)
Sorensen	2/16/2018	9,923	322,398
	2/16/2017	6,279	204,005
Goff	2/16/2018	75,818	2,463,327
	2/16/2017	54,084	1,757,189
Sterin (e)	N/A	—	—
Rucker (e)	N/A	—	—

(a) As discussed above under “Elements of Compensation—Long-Term Incentive Compensation,” all outstanding performance phantom units previously granted to our NEOs were converted to time-based phantom units on October 16, 2018.

(b) Reflects the grant date of the original performance phantom units.

(c) Amounts for Messrs. Sorensen and Goff reflect the number of ANDX phantom units, converted upon the MPC Merger from prior ANDX performance phantom unit awards, held on December 31, 2018. These awards were granted under the Andeavor Logistics LP 2011 Long-Term Incentive Plan and remain subject to their original vesting schedules. These awards generally provide for pro rata vesting based on the number of full months worked during the awards’ original performance period once the grantee becomes retirement eligible. Messrs. Sorensen and Goff became retirement eligible on June 19, 2018 and May 1, 2015, respectively. Under applicable tax rules, this retirement eligibility caused Messrs. Sorensen and Goff to “vest” in a pro rata portion of their ANDX awards for payroll tax (e.g., FICA taxes) purposes upon their conversion on October 1, 2018, because on and after such date no substantial risk of forfeiture applies to these awards. While these awards continue to be reflected in this table, the portion used to pay the associated taxes has been excluded from this table, and is instead included in the “Option Exercises and Units Vested in 2018” table below.

(d) The market value was calculated using the closing price of our common units on December 31, 2018 ($32.49).

(e) All outstanding awards held by Mr. Sterin and Ms. Rucker vested on an accelerated basis due to the termination of their employment on October 3, 2018 and October 1, 2018, respectively, in connection with the MPC Merger; however, due to Section 409A of the Internal Revenue Code, these awards will not be distributed until six months plus one day following each NEO’s respective termination date. They are reflected in the “Option Exercises and Units Vested in 2018” table.

Option Exercises and Units Vested in 2018

The following table provides information regarding performance phantom units that vested in 2018. We have not granted any options to purchase our units.

	Unit Awards
Name	Number of Units Acquired on Vesting	Value Realized on Vesting ($) (a)
Sorensen (b)	7,556	245,925
Goff (b)	66,396	2,161,585
Sterin (c)	42,146	1,324,466
Rucker (c)	32,080	1,089,923

(a) Amounts reflect the pre-tax gain realized upon vesting, which is the fair market value of the units on the vesting date. See “Elements of Compensation—Long-Term Incentive Compensation” for additional information on the performance phantom units.

(b) As discussed in footnote (c) to the Outstanding Equity at 2018 Fiscal Year-End table, during 2018, certain awards held by Messrs. Sorensen and Goff vested for payroll tax (e.g., FICA taxes) purposes due to their retirement eligibility under the applicable plans and agreements. Amounts in this column include the following numbers of such awards used to pay the associated taxes: Mr. Sorensen, 202 phantom units; Mr. Goff, 2,056 phantom units.

(c) Includes performance phantom units granted in 2016, 2017 and 2018 that vested and were paid out to pay required FICA taxes and associated income taxes. All outstanding awards held by Mr. Sterin and Ms. Rucker vested on an accelerated basis due to the termination of their employment on October 3, 2018 and October 1, 2018, respectively, in connection with the MPC Merger; however, due to Section 409A of the Internal Revenue Code, these awards will not be distributed until six months plus one day following each NEO’s respective termination date. The number of deferred phantom units included in this table is: Mr. Sterin, 39,112; and Ms. Rucker, 29,770. The value realized on vesting for these deferred phantom units was calculated using the closing price of our common units on December 31, 2018 ($32.49).

118 |

Executive Compensation

Pension Benefits in 2018

The following table shows the estimated pension benefits provided under the Andeavor Pension Plan and the Andeavor Restoration Retirement Plan (the “Restoration Plan”) for certain of our NEOs. As discussed above under “Compensation Decisions and Allocation,” our Sponsor allocated a portion of the 2018 compensation expenses, including pension expense, for Messrs. Woodward and Sorensen to us; however, the following table shows the full present value of the accumulated benefit for these NEOs. No portion of pension expense for the other NEOs was allocated to us.

Name	Plan Name	Number of Years of Credited Service (a)	Present Value of Accumulated Benefit ($) (b)	Payments During Last Fiscal Year ($)
Woodward	Andeavor Pension Plan	—	40,087	—
	Restoration Plan	—	3,556	—
Sorensen	Andeavor Pension Plan	22	986,643	—
	Restoration Plan	22	873,555	—

(a) Due to a freeze of credited service as of December 31, 2010, credited service values for the Andeavor Pension Plan are less than actual service values. Credited service is used to calculate the final average pay portion of the Pension Plan benefit. The Cash Balance portion of the retirement benefit that went into effect on January 1, 2011 does not utilize credited service. Mr. Woodward does not have any years of credited service as he was hired after the freeze went into effect.

(b) The present values of the accumulated plan benefits are equal to the value of the retirement benefits at the earliest unreduced age for each plan using the assumptions as of December 31, 2018 for financial reporting purposes. These assumptions include a discount rate of 4.22%, a cash balance interest crediting rate of 3.22%, the use of the RP-2018 Mortality Table with generational mortality improvements in accordance with Scale MP-2018 and for the Andeavor Pension Plan, that each employee will elect a lump sum payment at retirement using an interest rate of 4.22% and the PPA 2018 Mortality Table.

Andeavor Pension Plan

The Andeavor Pension Plan is a tax-qualified defined benefit retirement plan with a monthly benefit made up of two components: (i) a final average pay benefit for service through December 31, 2010, and (ii) a cash balance account based benefit for service after December 31, 2010. The final benefit payable under the Andeavor Pension Plan is equal to the value of the sum of both the final average pay and the Cash Balance components on the participant’s benefit commencement date.

For service prior to December 31, 2010, the final average pay benefit is 1.1% of final average compensation for each year of service through December 31, 2010, plus 0.5% of average compensation in excess of the Social Security Covered Compensation limit for each year of service through December 31, 2010, up to 35 years. Final average compensation is the monthly average of compensation (including base pay plus bonus, but limited to the maximum compensation and benefit limits allowable for qualified plans under the Internal Revenue Code) over the consecutive 36-month period in the last 120 months preceding retirement that produces the highest average.

For service after 2010, participants earn pay and interest credits under the cash balance component. Pay credits are determined based on a percentage of eligible pay at the end of each quarter, ranging from 4.5% to 8.5% of pay based on a participant’s age at the end of each quarter. Interest is credited quarterly on account balances based on a minimum of 3%, the 10-Year Treasury Bonds or the 30-Year Treasury Bonds, whichever is higher. The cash balance benefit component for service after 2010 is always based on the actual balance of the cash balance account as of the payment date and is not subject to any reduction for payment prior to normal retirement. Effective December 31, 2018, the Andeavor Pension Plan was frozen, meaning that no additional pay credits may be earned under the Plan after that date; provided, however, that Plan participants will continue to earn interest credits on their Plan cash balance accounts.

Benefits are generally payable the first day of the month following the attainment of age 65 and the completion of at least three years of service. If a participant qualifies for early retirement (age 50 with service plus age greater than or equal to 80, which is referred to as “80-point early retirement,” or age 55 with five years of service, which is referred to as “regular early retirement”), the final average pay benefit component will be reduced by a subsidized early retirement factor prior to age 65. Under the 80-point early retirement definition, the final average pay benefit component may be paid at age 60 without reduction or earlier than age 60 with a reduction of 5% per year for each year the age at retirement is less than 60. Under the regular early retirement definition, the final average pay benefit component may be paid at age 62 without reduction or earlier than age 62 with a reduction of approximately 7.14% per year for each year prior to age 62. If an employee does not qualify for early retirement upon separation from service, they will be eligible for an actuarially equivalent final average pay benefit based on their age at the date the benefit is paid without an early retirement subsidy.

As of December 31, 2018, Mr. Sorensen is eligible to receive a payment under the Andeavor Pension Plan without an early retirement subsidy for the final average pay portion of the benefit.

Andeavor Restoration Pension Plan

The Andeavor Restoration Pension Plan is a nonqualified plan designed to restore the benefit which is not provided under the qualified Pension Plan due to compensation and benefit limitations imposed under the Internal Revenue Code. Any participating

December 31, 2018 |119

Executive Compensation

NEO terminating employment prior to becoming eligible for a benefit under either the Andeavor Executive Security Plan or the Andeavor Supplemental Executive Retirement Plan, as applicable, and after attaining three years of service credit, will receive a supplemental pension benefit under this plan.

The plan provides a benefit equal to the difference between the actual qualified Pension Plan benefit paid to the participant, and the benefit that would have otherwise been paid to the participant under the Pension Plan, without regard to certain Internal Revenue Code limits. The plan also provides for certain death and disability benefits in the same manner as provided in the qualified Pension Plan. Generally, the death benefit provides an equivalent final average pay benefit and full Cash Balance account value as of the date of death. The disability benefit provides continued benefit accruals during the period of disability up to age 65. Effective December 31, 2018, the Andeavor Restoration Pension Plan was frozen, meaning that participants will accrue no additional benefits for periods after that date.

As of December 31, 2018, the present value of these death and disability benefits for Mr. Sorensen was $842,587 for death and $1,024,338 for disability.

Nonqualified Deferred Compensation in 2018

The following table provides information regarding the contributions to, and year-end balances under, the Andeavor Executive Deferred Compensation Plan for the NEOs in 2018. As the value of a participating NEO’s balance may be tied significantly to contributions made prior to the time he or she began providing services to us, the amount shown is not necessarily reflective of the expenses allocated to us.

Name		Executive Contributions in Last Fiscal Year ($) (a)	Company Contributions in Last Fiscal Year ($) (b)	Aggregate Earnings in Last Fiscal Year ($) (c)	Aggregate Withdrawals/Distributions ($) (d)	Aggregate Balance at Last Fiscal Year-End ($) (d) (e)
Sorensen	Andeavor Executive Deferred Compensation Plan	27,010	28,900	(8,023)	—	861,569
	Andeavor Logistics LP 2011 Long-Term Incentive Plan	—	306,974	—	6,993	285,083

(a) Amounts shown for the Andeavor Executive Deferred Compensation Plan include amounts reflected for Mr. Sorensen in the “Salary” and Non-Equity Incentive Plan Compensation” columns of the 2018 Summary Compensation Table.

(b) As discussed above under “Compensation Decisions and Allocation,” our Sponsor allocates a portion of the compensation expenses for Mr. Sorensen to us. Amounts shown for the Andeavor Executive Deferred Compensation Plan represent the full amounts of the contributions, earnings and year-end balances for Mr. Sorensen; the portion allocated to us is included in the “All Other Compensation” column of the 2018 Summary Compensation Table. Amounts shown for the Andeavor Logistics LP 2011 Long-Term Incentive Plan represent the value of Mr. Sorensen’s phantom units and accrued distribution equivalents under this plan, calculated using the December 19, 2018 closing price of our common units ($34.62).

(c) Amounts shown for the Andeavor Executive Deferred Compensation Plan reflect the change in the market value pertaining to the investment funds in which Mr. Sorensen has chosen to invest his contributions and Andeavor’s contribution under the plan.

(d) As discussed in footnote (c) to the “Outstanding Equity at 2018 Fiscal Year-End” table, during 2018, certain awards held by Mr. Sorensen vested for income tax and payroll tax (e.g., FICA taxes) purposes due to his retirement eligibility under the applicable plans and agreements. 202 phantom units were withheld for such taxes as of December 19, 2018. Using the closing price of our common units on that date ($34.62), the taxes totaled $6,993. As of December 31, 2018, Mr. Sorensen had 6,488 vested, but as yet unpaid, phantom units.

(e) Amounts shown for the Andeavor Logistics LP 2011 Long-Term Incentive Plan represent the value of Mr. Sorensen’s phantom units and accrued distribution equivalents under this plan, calculated using the December 31, 2018 closing price of our common units ($32.49).

Andeavor Executive Deferred Compensation Plan

The Andeavor Executive Deferred Compensation Plan is an unfunded nonqualified deferred compensation plan maintained for a select group of management or highly compensated employees. The Plan generally provided participants the opportunity to defer up to 50% of their base salary and/or up to 100% of their bonus compensation each year in a tax-advantaged manner. Also, the Plan matched participants’ base salary deferrals dollar-for-dollar up to 6% of eligible compensation above the Internal Revenue Code annual compensation limit ($275,000 for 2018), and credited a discretionary profit sharing contribution in an amount up to 2% of each participant’s Plan-considered compensation. Mr. Sorensen is fully vested in his notional Plan account. Plan participants may make notional investments of their notional Plan accounts from among certain of the investment options offered by Andeavor LLC to participants under the Plan, and participants’ notional Plan accounts are credited with notional earnings and losses based on the result of those investment elections. Effective at the close of December 31, 2018, the Plan was frozen as to new participants and to cease additional credits (e.g., participant deferrals of compensation, and company contribution credits) to existing participants’ notional Plan accounts for all periods after December 31, 2018; provided, however, that credits will be made for participants’ existing deferral elections for Plan-considered compensation relating to 2018. Plan participants generally receive payment of their Plan benefits on the later of the January following separation from service or the first business day of the seventh month following separation from service, or, in certain circumstances, at a participant-elected date or no later than January 31, 2020.

120 |

Executive Compensation

2018 Potential Payments Upon Termination or Change in Control

The following table reflects the estimated amount of compensation for each NEO upon certain termination events, in each case assuming such event occurred as of December 31, 2018, under the plans and agreements in place on such date. This compensation is in addition to the pension benefits, including certain termination-related pension benefits, described above under “Pension Benefits in 2018.” The actual payments an executive would be entitled to could only be determined based upon the actual occurrence and circumstances surrounding an actual termination.

Name	Scenario	Severance ($)	Additional Pension Benefits ($) (a)	Accelerated Equity Vesting ($)	Other Benefits ($) (b)	Total ($)
Sorensen	Retirement (c)	—	—	210,795	—	210,795
	Resignation (d)	—	—	210,795	—	210,795
	Involuntary Termination without Cause or Voluntary Termination (d)	1,550,608	—	526,403	2,284	2,079,295
	Involuntary Termination for Cause	—	—	—	—	—
	Change in Control with Qualified Termination	2,188,245	2,120,383	526,403	50,017	4,885,048
	Death	—	—	210,795	—	210,795
	Disability	—	—	210,795	—	210,795
Goff	Retirement (c)	—	—	1,723,562	—	1,723,562
	Resignation (d)	—	—	1,723,562	—	1,723,562
	Involuntary Termination without Cause or Voluntary Termination (d)	—	—	4,220,516	—	4,220,516
	Involuntary Termination for Cause	—	—	—	—	—
	Change in Control with Qualified Termination	—	—	4,220,516	—	4,220,516
	Death	—	—	1,723,562	—	1,723,562
	Disability	—	—	1,723,562	—	1,723,562

(a) Pension benefits for our NEOs are reflected in the “2018 Pension Benefits” table above. Amounts in this column for Mr. Sorensen represent additional pension benefits attributable solely to the final average pay formula under the Andeavor Pension Plan and the Andeavor Restoration Pension Plan. The incremental retirement benefits included in this amount were calculated using the following assumptions: the present value is equal to the value of the normal retirement benefits under the Andeavor Pension Plan, adjusted to incorporate the enhancements listed below, at the earliest unreduced age assuming a discount rate of 4.22%, a cash balance interest crediting rate of 3.22%, the use of the RP-2018 Mortality Table with generational mortality improvements in accordance with Scale MP-2018, and assuming the election of a lump sum payment at retirement using an interest rate of 4.22% and the PPA 2019 Mortality Table. The referenced enhancements are (i) final average pay is calculated using base salary in effect immediately prior to separation from service and the highest bonus paid during the three years immediately preceding the separation from service, but not less than the final average pay taken into account in the determination of the NEO’s actual pension benefit, and (ii) the service used in determining the normal retirement benefit is equal to actual service for benefit accrual purposes plus three years (three years of additional age is also incorporated).

(b) Includes 36 months of continued health, dental and life insurance coverage. In the event of death, life insurance would be paid out to the estate of Mr. Sorensen in the amount of $1 million.

(c) Assumes retirement from ANDX and all affiliates, including MPC.

(d) As Messrs. Sorensen and Goff are retirement eligible, any resignation, voluntary termination, or involuntary termination without cause would be deemed a retirement under the applicable plans and agreements.

As discussed above under “Compensation Decisions and Allocation of Executive Compensation,” our Sponsor allocates a portion of the compensation expenses for Mr. Sorensen to us. Amounts in this table and the discussion below reflect the portion (90%) of Mr. Sorensen’s severance payment or benefit that would be allocated to us by our Sponsor. Other than the accelerated vesting of Mr. Goff’s phantom units granted under our LTIP, as reflected in the table above, no part of the severance benefits for Messrs. Heminger, Woodward or Goff would be allocated to us. Mr. Sterin and Ms. Rucker are not included in this table as they were no longer employed by us as of December 31, 2018.

Severance

Involuntary Termination Without Cause

Because a change in control of Andeavor occurred effective October 1, 2018, under the Andeavor Executive Severance and Change-in-Control Plan, Mr. Sorensen would receive an amount equal to two times the sum of his base salary and the average bonuses paid during the preceding three years. Severance would be paid in a lump sum following the end of the six months after termination.

December 31, 2018 |121

Executive Compensation

Termination with a Change in Control

In the event of termination by our Sponsor without cause or by Mr. Sorensen with good reason within two years following a change in control of us, Mr. Sorensen would receive an amount equal to up to three times the sum of his current annualized base salary plus three times the highest bonus paid in the three years before the termination or change in control. The severance amounts would be paid in a lump sum after his termination. See “MPC’s Change in Control Plan” below for additional information.

Accelerated Equity Vesting

Involuntary Termination Without Cause

Pursuant to the applicable award agreements, Mr. Sorensen and Mr. Goff would vest in their phantom units and would be paid the accumulated DERs on those units.

Termination with a Change in Control

Pursuant to the applicable award agreements, in the event of a qualifying termination, Mr. Sorensen and Mr. Goff would vest in their phantom units and would be paid the accumulated DERs accumulated on those units.

Retirement

Pursuant to the applicable award agreements, Mr. Sorensen and Mr. Goff would receive a prorated award of their phantom units and would be paid the accumulated DERs on those units.

Death and Disability

Pursuant to the applicable award agreements, Mr. Sorensen and Mr. Goff would receive a prorated award of their phantom units with the accumulated DERs.

Other Benefits

Involuntary Termination Without Cause

Because a change in control of Andeavor occurred effective October 1, 2018, under Andeavor’s Executive Severance and Change-in-Control Plan, Mr. Sorensen would receive medical benefits for two years following the termination.

MPC’s Change in Control Plan

Our NEOs participate in the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan. The plan is designed to pay benefits only upon a change in control and a Qualified Termination. A Qualified Termination generally occurs when an NEO separates from service from MPC and its affiliates, including us, in connection with, or within two years after, a change in control unless such separation is:

• due to death or disability;

• for cause;

• voluntary, unless the NEO has good reason (defined as a reduction in the NEO’s roles, responsibilities, pay or benefits, or the NEO being required to relocate more than 50 miles from his or her current location); or

• on or after the date the NEO attains age 65.

Upon a change in control of MPC or us and a Qualified Termination, each NEO is eligible to receive:

• a cash payment of up to three times the sum of the NEO’s current annualized base salary plus three times the highest bonus paid in the three years before the termination or change in control;

• life and health insurance benefits for up to 36 months after termination at the lesser of the current cost or the active employee cost;

• an additional three years of service credit and three years of age credit for purposes of retiree health and life insurance benefits;

• a cash payment equal to the actuarial equivalent of the difference between amounts receivable by the NEO under the final average pay formula in our pension plans and those that would be payable if: (i) the NEO had an additional three years of participation service credit; (ii) the NEO’s final average pay were the higher of the NEO’s salary at the time of the change in control event or Qualified Termination plus the NEO’s highest annual bonus from the preceding three years (for purposes of determining early retirement commencement factors, the NEO is credited with three additional years of vesting service and three additional years of age);

• a cash payment equal to the difference between amounts receivable under our tax-qualified and nonqualified defined contribution type retirement and deferred compensation plans and amounts that would have been received if the NEO’s defined contribution plan account had been fully vested; and

• accelerated vesting of all outstanding MPC LTI awards.

122 |

Executive Compensation

CEO Pay Ratio

As of December 31, 2018, neither we, nor our subsidiaries, directly employ any employees. Because we do not have any employees and do not determine or pay total compensation to the employees of our Sponsor who manage and operate our business, we do not have a median employee whose total compensation can be compared to the total compensation of our chief executive officer.

Director Compensation

Our directors who also serve as officers or employees of either our general partner or our Sponsor do not receive additional compensation for their service as our directors. Directors who are not officers or employees of either our general partner or our Sponsor receive compensation as “non-employee directors.”

Compensation Program for Non-Employee Directors

Following is the compensation package established for our non-employee directors for 2018:

Role	Cash Retainer ($)	Service Phantom Unit Award ($)	Committee Chair Retainer ($)	Total ($)
Audit Committee Chair	65,000	90,000	15,000	170,000
Conflicts Committee Chair	65,000	90,000	15,000	170,000
All Other Directors	65,000	90,000	—	155,000

Directors received a meeting fee of $1,500 for each meeting attended (for attendance in person or by telephone). We also reimburse our non-employee directors for travel and lodging expenses they incur in connection with attending meetings of the Board or its committees.

Service phantom units granted to non-employee directors under our LTIP were typically granted annually to directors in conjunction with the Board’s approval of our Annual Report on Form 10-K. New non-employee directors receive a pro rata award of service phantom units upon joining the Board. The number of units granted was determined by dividing the equity portion of the annual retainer by the average closing price of our common units on the NYSE over a ten business-day period ending on the third business day prior to the grant date and rounding any resulting fractional units to the nearest whole unit. Messrs. Bromark, Cornelius, Dreessen, Lamanna, Stevens and Wiley each received 1,808 phantom units in conjunction with the Board’s approval of our Annual Report on Form 10-K in February 2018. Mr. Cornelius and Ms. Dreessen each received 228 phantom units on January 1, 2018, the effective date of their election to the Board. As a result of the MPC Merger, on October 1, 2018, all then outstanding phantom units were paid out per the terms of the awards.

Mr. Semple received 456 phantom units in the fourth quarter of 2018 in respect of his October 1, 2018 election to the Board. These phantom units will vest one year from the grant date. Cash distribution equivalent rights accrue with respect to these phantom units and are distributed upon vesting. If a non-employee director’s termination from the Board is due to death or disability, his or her service phantom units will automatically vest along with any accrued cash distribution equivalent rights. If termination is due to any other reason, the non-employee director will receive a prorated award for the number of full months served during the vesting period along with any accrued cash distribution equivalent rights. The prorated award vests one year from the grant date.

Under MPC’s matching gifts program, non-employee directors may elect to have MPC match up to $10,000 of their contributions to certain tax-exempt educational institutions each year. The annual limit is applied based on the date of the director’s gift to the institution. Due to processing delays, the actual amount paid out on behalf of a director may exceed $10,000 in a given year.

We indemnify our directors for any actions associated with being a director to the fullest extent permitted under Delaware law, and reimburse them for all expenses incurred while serving as a director.

December 31, 2018 |123

Executive Compensation

2019 Program Changes

In October 2018, following a presentation and discussion with Pay Governance LLC, the compensation consultant for MPC’s compensation committee, our CEO and Chairman recommended, and the Board determined, to make certain changes to the non-employee director compensation program to more closely align with market data. The following table shows the changes in compensation, effective January 1, 2019.

Compensation Component	2018 ($)	2019 ($)
Cash Retainer	65,000	90,000
Deferred Phantom Unit Equity Award	90,000	110,000
Lead Director Retainer	N/A	15,000
Audit Committee Chair Retainer	15,000	15,000
Conflicts Committee Chair Retainer	15,000	15,000
MLP Representative MPC Board Observer Retainer	N/A	62,500

Meeting fees were largely eliminated, except that members of the Conflicts Committee will receive a meeting fee of $1,500 for each Conflicts Committee meeting attended in excess of six meetings per year.

Cash retainers, lead director and committee chair fees are paid in cash in equal quarterly installments at the beginning of each calendar quarter.

Phantom unit awards are granted in equal quarterly installments at the beginning of each calendar quarter. They are not subject to any risk of forfeiture once granted and are automatically deferred until departure from the Board, at which time they are settled in common units. Distribution equivalents in the form of additional phantom unit awards are credited to each director’s deferred account as and when distributions on common units are paid.

2018 Director Compensation Table

The following table shows the compensation we paid to our non-employee directors in 2018:

Name	Fees Earned or Paid in Cash ($)	Service Phantom Unit Awards ($) (a)	All Other Compensation ($)	Total ($)
Raymond J. Bromark (b)	94,500	86,386	—	180,886
Sigmund L. Cornelius	122,000	96,918	—	218,918
Ruth I. Dreessen	110,750	96,918	—	207,668
James H. Lamanna	107,000	86,386	—	193,386
Thomas C. O’Connor (c)	215	—	—	215
Frank M. Semple (d)	34,875	22,709	—	57,584
Jeff A. Stevens (e)	57,750	86,386	—	144,136
Michael E. Wiley (e)	57,750	86,386	—	144,136

(a) Amounts shown represent the aggregate grant date fair value of the directors’ portion of the annual retainer paid in service phantom units computed in accordance with FASB ASC Topic 718. Non-employee directors generally received an annual grant of phantom units with a grant date fair value of $86,386. Mr. Cornelius and Ms. Dreessen joined the Board effective January 1, 2018, and each received a prorated award of phantom units with a grant date fair value of $10,532. Mr. Semple joined the Board effective October 1, 2018, and received an award of phantom units for the fourth quarter with a grant date fair value of $22,709. As a result of the MPC Merger, on October 1, 2018, all then-outstanding outstanding phantom units were paid out per the terms of the awards. The only service phantom units outstanding as of December 31, 2018 were the 456 units granted to Mr. Semple in respect of his election to the Board on October 1, 2018.

(b) Mr. Bromark retired from the Board effective September 27, 2018, at which time his outstanding phantom units vested.

(c) Mr. O’Connor retired from the Board effective January 1, 2018. Amounts shown for him reflect a prorated portion of his 2018 Board retainer and Conflicts Committee Chair retainers.

(d) Mr. Semple joined the Board effective October 1, 2018 in connection with the MPC Merger. In addition to his service as our director, he serves as our Representative Observer to attend certain MPC Board and committee meetings, a role in which he acts as a liaison between the MPC Board and us.

(e) Messrs. Stevens and Wiley resigned from the Board effective October 1, 2018 in connection with the MPC Merger.

124 |

Security Ownership and Related Unitholder Matters

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership by Directors and Executive Officers

The following table shows the number of ANDX common units and shares of MPC common stock beneficially owned as of January 31, 2019 by each director and NEO, and by all current directors and executive officers as a group. The address for each person is c/o Andeavor Logistics LP, 200 East Hardin Street, Findlay, Ohio 45840. Unless otherwise indicated, to our knowledge, each person or member of the group listed has sole voting and investment power with respect to the securities shown, and none of the units or shares shown is pledged as security. As of January 31, 2019, there were 245,551,332 ANDX common units outstanding (including 156,173,128 common units held by MPC and its affiliates) and 676,152,130 shares of MPC common stock outstanding.

	Amount and Nature of Beneficial Ownership				Percent of Total Outstanding (%)
	ANDX Common Units		MPC Common Stock		ANDX	MPC
Pamela K. M. Beall	—		125,226	(f)	*	*
Sigmund L. Cornelius	4,158	(a)	—		*	*
Ruth I. Dreessen	2,850	(a)	—		*	*
Gregory J. Goff	300,378	(b)	2,035,418	(b)(f)	*	*
Timothy T. Griffith	—		280,749	(f)	*	*
Gary R. Heminger	—		3,065,847	(f)(g)	*	*
Michael J. Hennigan	—		33,502	(f)	*	*
James H. Lamanna	15,816	(a)	—		*	*
Kim K. W. Rucker	29,770	(c)	106,091	(c)(h)	*	*
Frank M. Semple	1,270	(a)	4,707	(h)	*	*
Don J. Sorensen	25,822	(d)	33,339	(d)	*	*
Steven M. Sterin	39,112	(e)	133,314	(e)	*	*
Donald C. Templin	—		581,422	(f)	*	*
D. Andrew Woodward	—		6,696	(i)	*	*
All Current Directors and Executive Officers as a Group (14 individuals)	350,294		6,285,808	(f)(j)	*	*

* Less than 1% of the common units or common shares outstanding, as applicable.

(a) Includes 814 phantom units that will settle in common units upon the director’s retirement from service on the Board. Mr. Semple’s amount also includes 456 phantom units that will vest and settle in common units on October 1, 2019.

(b) ANDX total includes 129,902 time-based phantom units, a portion of which may be forfeited under certain conditions, that will settle in common units. MPC total includes (i) 483,554 restricted stock units converted from previously outstanding Andeavor awards, a portion of which may be forfeited under certain conditions, (ii) 226,383 shares held by G Goff Foundation Inc., for which Mr. Goff serves as a director with shared voting and investment power, (iii) 38,875 shares held in trust for which Mr. Goff acts as trustee with shared voting and investment power, and (iv) shares held jointly with his spouse.

(c) ANDX total includes 29,770 time-based phantom units that will settle in common units on April 2, 2019. MPC total includes 105,018 restricted stock units that will settle in shares of common stock on April 2, 2019.

(d) ANDX total includes 16,202 time-based phantom units, a portion of which may be forfeited under certain conditions, that will settle in common units. MPC total includes 20,653 restricted stock units converted from previously outstanding Andeavor awards, a portion of which may be forfeited under certain conditions.

(e) ANDX total includes 39,112 time-based phantom units that will settle in common units on April 4, 2019. MPC total includes 133,314 restricted stock units that will settle in shares of common stock on April 4, 2019.

(f) Includes all stock options exercisable within 60 days of January 31, 2019 as follows: Ms. Beall, 83,440; Mr. Goff, 283,329; Mr. Griffith, 233,800; Mr. Heminger, 2,498,655; Mr. Hennigan, 10,075; Mr. Templin, 495,395; all other executive officers, 71,357.

(g) Includes 206,202 shares of common stock indirectly beneficially held in trust by Mr. Heminger.

(h) Includes restricted stock unit awards that will settle in shares of common stock upon the director’s retirement from service on the MPC board or observer status as follows: Ms. Rucker, 1,073; Mr. Semple, 4,707.

(i) Includes 5,081 restricted stock units converted from previously outstanding Andeavor awards, a portion of which may be forfeited under certain conditions.

(j) Includes 23,912 restricted stock units held by all other executive officers, which were converted from previously outstanding Andeavor awards and a portion of which may be forfeited under certain conditions.

December 31, 2018 |125

Security Ownership and Related Unitholder Matters

Security Ownership by Certain Beneficial Owners

The following table shows the beneficial owners of 5% or more of any class of our outstanding units, based on information available as of February 21, 2019. Unless otherwise indicated, each person listed has sole voting and investment power with respect to the common units listed, and none of the common units shown are pledged as security.

	Amount and Nature of Beneficial Ownership
Name and Address of Beneficial Owner	Number of Common Units	Percent of Common Units (a)
Marathon Petroleum Corporation (b)      539 South Main Street      Findlay, Ohio 45840	156,173,128	63.6%
Tortoise Capital Advisors, LLC (c)      11550 Ash Street, Suite 300      Leawood, KS 66211	14,650,854	6.0%

(a) Based on 245,551,332 common units representing limited partner interests outstanding (including 156,173,128 common units held by MPC and its affiliates) on February 21, 2019.

(b) The 156,173,128 common units are directly held by TLGP and Western Refining Southwest Inc., which are wholly owned indirect subsidiaries of MPC. As the ultimate parent company of each such entity, MPC may be deemed to beneficially own the units.

(c) Based on Amendment No. 10 to a Schedule 13G/A filed with the SEC on February 12, 2019, Tortoise Capital Advisors has sole voting and dispositive power with respect to 369,483 common units, shared voting power with respect to 13,055,751 common units and shared dispositive power with respect to 14,281,371 common units.

Equity Compensation Plan Information

Information Regarding Tesoro Logistics GP, LLC’s Equity Compensation Plans, as of December 31, 2018

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in the First Column) (c)
Equity compensation plans approved by security holders	379,318	—	943,466
Equity compensation plans not approved by security holders	—	—	—
Total	379,318	—	943,466

(a) Includes only phantom unit and time-based phantom unit awards that have been granted under the Andeavor Logistics LP 2011 Long-Term Incentive Plan, as amended and restated, each of which represents a right to receive, upon vesting and payout, a common unit. No unit options have been granted. These amounts do not include 24,922 phantom unit awards outstanding under the Western Refining Logistics, LP 2013 Long-Term Incentive Plan, each of which represents a right to receive, upon vesting and payout, a common unit.

(b) There is no exercise price associated with the awards.

(c) Reflects the common units available for issuance pursuant to the Andeavor Logistics LP 2011 Long-Term Incentive Plan. All of these shares may be available for awards other than options, warrants and rights. All granting authority under the Western Refining Logistics, LP 2013 Long-Term Incentive Plan was revoked at the time of the WNRL Merger.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Policy and Procedures with Respect to Related Person Transactions

Our Board has adopted a formal written related person transactions policy to establish procedures for the notification, review, approval, ratification and disclosure of related person transactions. This policy is available on our website at www.andeavorlogistics.com under the heading “Investors” and the subheading “Governance.” Under the policy, a “related person” includes any director, nominee for director, executive officer, or a known beneficial holder of more than 5% of any class of our voting securities (other than our Sponsor or its affiliates) or any immediate family member of a director, nominee for director, executive officer or more than 5% owner. This procedure applies to any transaction, arrangement or relationship and any series of similar transactions, arrangements or relationships in which (i) we are a participant, (ii) the amount involved exceeds $120,000, and (iii) a related person has a direct or indirect material interest. The following transactions, arrangements or relationships, however, have the Board’s standing pre-approval:

• Payment of compensation to an executive officer or director of our general partner if the compensation is otherwise required to be disclosed in our filings with the SEC;

126 |

Certain Relationships and Related Transactions and Director Independence

• Any transaction where the related person’s interest arises solely from the ownership of securities;

• Any ongoing employment relationship provided that such employment relationship will be subject to initial review and approval; and

• Any transaction between any of our subsidiaries or us, on the one hand, and our general partner or any of its affiliates, on the other hand; provided, however, that such transaction is approved consistent with our Partnership Agreement.

Any related person transaction that is identified prior to its consummation will be consummated only if the Board approves it in advance. If the related person transaction is identified after it commences, it will be promptly submitted to the Board or the Chairman for ratification, amendment or rescission. If the transaction has been completed, the Board or the Chairman will evaluate the transaction to determine if rescission is appropriate.

In determining whether to approve or ratify a related person transaction, the Board or the Chairman will consider all relevant facts and circumstances, including but not limited to:

• the benefits to us, including the business justification;

• if the related person is a director or an immediate family member of a director, the impact on the director’s independence;

• the availability of other sources for comparable products or services;

• the terms of the transaction and the terms available to unrelated third parties or to employees generally; and

• whether the transaction is consistent with our Code of Business Conduct.

Our Relationship with MPC

On October 1, 2018, MPC completed its acquisition of Andeavor in accordance with the Agreement and Plan of Merger, dated as of April 29, 2018, as amended, under which MPC acquired Andeavor. As a result of the MPC Merger, our general partner became a wholly-owned subsidiary of MPC. Unless the context otherwise requires, references in this Item 13 to our “Sponsor” refer to Andeavor and its affiliates for events occurring through September 30, 2018, and to MPC and its affiliates, including Andeavor, for events occurring on or after October 1, 2018.

As of February 21, 2019, MPC owned through its affiliates, including Andeavor, 156,173,128 of our common units, representing approximately 64% of our common units outstanding, and 100% of our general partner. Our general partner manages our operations and activities through its officers and directors. In addition, Mr. Heminger is Chairman of the Board and Chief Executive Officer of MPC, and Messrs. Goff, Griffith and Templin serve as officers of MPC. Accordingly, we view transactions between MPC and its affiliates, including Andeavor, on the one hand, and us, on the other hand, as related party transactions and have provided the following disclosures with respect to such transactions during 2018.

Acquisitions

On August 6, 2018, we completed the 2018 Drop Down for total consideration of $1.55 billion. These assets include gathering, storage and transportation assets in the Permian Basin; legacy Western Refining, Inc. assets and associated crude terminals; the majority of our Sponsor’s remaining refining terminalling, transportation and storage assets; and equity method investments in ALRP, MPL and PNAC. In addition, the Conan Crude Oil Gathering System and LARIP were transferred at cost plus incurred interest. The transaction was funded in part by issuing 28,283,742 common units to our Sponsor with the remainder funded with borrowings under our Dropdown Credit Facility.

Distributions

Pursuant to our partnership agreement, we make cash distributions to our unitholders, including to our Sponsor as the direct and indirect holder of approximately 156,173,128 common units. During 2018, we distributed approximately $493 million to our Sponsor and its affiliates with respect to common units. Our Sponsor waived its right to $60 million of distributions related to incentive distribution rights paid in 2018.

Under our omnibus agreement and secondment and logistics services agreements, we reimburse our general partner and its affiliates, including our Sponsor, for all costs and expenses incurred on our behalf. The amount we reimbursed in 2018 was $311 million.

Transactions and Commercial and Other Agreements

We have multiple long-term, fee-based transportation and storage services agreements, as well as a variety of operating services agreements, management services agreements, employee services agreements, an omnibus agreement and a loan agreement. See Note 3 to our consolidated financial statements in Item 8 for information regarding related party activities with our Sponsor.

Loan Agreement

On December 21, 2018, we entered into the MPC Loan Agreement. Under the terms of the MPC Loan Agreement, MPC will make a loan or loans to us on a revolving basis as requested by us and as agreed to by MPC, in an aggregate principal amount

December 31, 2018 |127

Certain Relationships and Related Transactions and Director Independence

not to exceed $500 millionat any one time. The MPC Loan Agreement matures and the entire unpaid principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, owed by the Partnership under the MPC Loan Agreement will become due and payable on December 21, 2023, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the Loan, together with all accrued and unpaid interest and other amounts, if any, at any time prior to the maturity date. Interest will accrue on the unpaid principal amount of the Loan at a rate equal to the sum of (i) the one-month term LIBOR for dollar deposits, plus (ii) a premium of1.75basis points (or such lower premium then applicable under the Partnership’s credit agreements). The outstanding balance on this loan as of December 31, 2018, was $0.

Director Independence

See “Director Independence” in Item 10.

Item 14. Principal Accountant Fees and Services

The Audit Committee has selected Ernst & Young LLP (“EY”) to serve as our independent registered public accounting firm for the fiscal year ending December 31, 2018. The Audit Committee in its discretion may select a different registered public accounting firm at any time during the year if it determines that such a change would be in the best interests of our unitholders and us.

Auditor Fees

The following table presents fees billed for the years ended December 31, 2018 and 2017, for professional services performed by EY (in thousands).

	Year Ended December 31,
	2018		2017
Audit Fees (a)	$	2,220	$	2,369
Audit-Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
Total	$	2,220	$	2,369

(a) Audit Fees represent the aggregate fees for professional services rendered by EY in connection with its audits of our consolidated financial statements, including the audits of internal control over financial reporting, reviews of the consolidated financial statements included in our Quarterly Reports on Form 10-Q and services that were provided in connection with registration statements, comfort letters and accounting consultations.

Pre-Approval of Audit Services

In accordance with the Audit Committee charter, all audit and permitted non-audit services performed by EY in 2018 and 2017 were pre-approved by the Audit Committee. The Audit Committee’s pre-approval procedures provide for pre-approval of specifically described audit, audit-related and tax services by the Audit Committee on an annual basis as long as the Audit Committee is informed of each service and the services do not exceed certain pre-established thresholds. The procedures also authorize the Audit Committee to delegate to the Chairman of the Audit Committee pre-approval authorization with respect to audit and permitted non-audit services; any such services that are approved by the Audit Committee Chairman must be ratified at the next regularly scheduled meeting of the Audit Committee.

128 |

Exhibits and Financial Statement Schedules

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a)    1. Financial Statements

The following consolidated financial statements of Andeavor Logistics LP and its subsidiaries are included in Item 8 of this Form 10-K:

	Page
Report of Independent Registered Public Accounting Firm (Ernst & Young LLP)	61
Consolidated Statements of Operations - Years Ended December 31, 2018, 2017 and 2016	62
Consolidated Balance Sheets - December 31, 2018 and 2017	63
Consolidated Statements of Partners’ Equity - Years Ended December 31, 2018, 2017 and 2016	64
Consolidated Statements of Cash Flows - Years Ended December 31, 2018, 2017 and 2016	65
Notes to Consolidated Financial Statements	66

2. Financial Statement Schedules

No financial statement schedules are submitted because of the absence of the conditions under which they are required, the required information is insignificant or because the required information is included in the consolidated financial statements.

3. Exhibits

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
2.1	Contribution, Conveyance and Assumption Agreement, dated as of November 12, 2015, among Tesoro Corporation, Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Tesoro SoCal Pipeline Company LLC, Tesoro Refining & Marketing Company LLC and Carson Cogeneration Company	8-K	2.1	11/12/2015
2.2	Contribution, Conveyance and Assumption Agreement, dated as of July 1, 2016, among Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Tesoro Alaska Company LLC and Tesoro Corporation	8-K	2.1	7/7/2016
2.3	Revision to the Contribution, Conveyance and Assumption Agreement, dated as of July 27, 2016, among Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Tesoro Alaska Company LLC and Tesoro Corporation	10-Q	2.2	11/2/2016
2.4	Revision to the Contribution, Conveyance and Assumption Agreement, dated as of November 21, 2016, by and among Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Tesoro Corporation and Tesoro Refining & Marketing Company LLC	10-K	2.4	2/21/2017
‡2.5	Contribution, Conveyance and Assumption Agreement, dated as of November 8, 2017, by and among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Andeavor and Tesoro Refining & Marketing Company LLC	8-K	2.1	11/8/2017
2.6	Membership Interest Purchase Agreement, dated as of October 19, 2014, between Tesoro Logistics LP and QEP Field Services Company	8-K	2.1	10/20/2014
2.7	Amendment No. 1 to Membership Interest Purchase Agreement, dated as of December 2, 2014, between Tesoro Logistics LP and QEP Field Services Company	8-K	2.2	12/8/2014
2.8	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, TLLPMerger Sub LLC, QEPMidstream Partners, LP, and QEPMidstream Partners GP, LLC	8-K	2.1	4/6/2015
‡2.9	Agreement and Plan of Merger, dated as of August 13, 2017, by and among Andeavor Logistics, LP, Tesoro Logistics GP, LLC, Western Refining Logistics, LP, Western Refining Logistics GP, LLC, WNRL Merger Sub LLC and WNRL GP Merger Sub LLC	8-K	2.1	8/14/2017
‡2.10	First Amendment to Contribution, Conveyance and Assumption Agreement, dated January 1, 2018, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Logistics Operations LLC, Andeavor, and Tesoro Refining & Marketing Company LLC	10-Q	2.3	5/7/2018

December 31, 2018 |129

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
2.11	Contribution, Conveyance and Assumption Agreement, dated as of August 6, 2018, by and among Andeavor Logistics LP, Tesoro Logistics Operations LLC, Tesoro Logistics Pipelines LLC, Western Refining Terminals, LLC, Western Refining Pipeline, LLC, Tesoro High Plains Pipeline Company LLC, Western Refining Logistics LP, Tesoro SoCal Pipeline Company LLC, WNRL Energy, LLC, Andeavor, Tesoro Refining & Marketing Company LLC, Western Refining Southwest, Inc., Tesoro Great Plains Gathering & Marketing LLC and Tesoro Great Plains Midstream LLC.	8-K	2.1	8/7/2018
2.12	First Amendment to Contribution, Conveyance and Assumption Agreement, effective August 6, 2018, by and among Andeavor Logistics LP, Tesoro Logistics Operations LLC, Tesoro Logistics Pipelines LLC, Western Refining Terminals, LLC, Western Refining Pipeline, LLC, Tesoro High Plains Pipeline Company LLC, Western Refining Logistics LP, Tesoro SoCal Pipeline Company LLC, WNRL Energy, LLC, Andeavor, Tesoro Refining & Marketing Company LLC, Western Refining Southwest, Inc., Tesoro Great Plains Gathering & Marketing LLC and Tesoro Great Plains Midstream LLC	10-Q	2.5	11/7/2018
3.1	Amended and Restated Certificate of Limited Partnership of Andeavor Logistics LP, dated October 17, 2018	8-K	3.1	10/29/2018
3.2	Third Amended and Restated Agreement of Limited Partnership of Andeavor Logistics LP, dated December 1, 2017	8-K	3.1	12/1/2017
3.3	Certificate of Formation of Tesoro Logistics GP, LLC	S-1 (File No. 333-171525)	3.3	1/4/2011
3.4	Third Amended and Restated Limited Liability Company Agreement of Tesoro Logistics GP, LLC, dated as of August 6, 2018, by and among Tesoro Logistics GP, LLC, Western Refining Southwest, Inc., Tesoro Refining & Marketing Company LLC and Tesoro Alaska Company LLC.	8-K	3.1	8/7/2018
3.5	Certificate of Amendment to the Certificate of Formation of Tesoro Logistics GP, LLC, dated October 1, 2018.	8-K	3.3	10/2/2018
3.6	Amendment to Third Amended and Restated Limited Liability Company Agreement of Tesoro Logistics GP, LLC, dated October 1, 2018.	8-K	3.4	10/2/2018
3.7	First Amendment to Third Amended and Restated Agreement of Limited Partnership of Andeavor Logistics LP, dated October 1, 2018	8-K	3.2	10/2/2018
4.1	Indenture, dated as of October 29, 2014, among Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 5.50% Senior Notes due 2019 and the 6.25% Senior Notes due 2022	8-K	4.1	10/29/2014
4.2	Indenture, dated as of May 12, 2016, among Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 6.375% Senior Notes due 2024	8-K	4.3	5/12/2016
4.3	Indenture, dated as of December 2, 2016, among Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 5.25% Senior Notes due 2025	8-K	4.1	12/2/2016
4.4	Indenture, dated as of November 28, 2017, among Tesoro Logistics LP, Tesoro Logistics Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 3.500% Senior Notes due 2022, 4.250% Senior Notes due 2027 and 5.200% Senior Notes due 2047	8-K	4.1	11/28/2017
10.1	Third Amended and Restated Senior Secured Revolving Credit Agreement, dated as of January 29, 2016, among Tesoro Logistics LP, Bank of America, N.A., as administrative agent, and the other lenders party thereto	8-K	10.1	2/3/2016
10.2	Agreement and Consent, dated as of November 9, 2017, among Andeavor Logistics LP, certain subsidiaries of Andeavor Logistics LP party thereto, the lenders party thereto, and Bank of America, N.A., as Administrative Agent	8-K	10.1	11/13/2017
10.3	Senior Secured Revolving Credit Agreement, dated as of January 29, 2016, among Tesoro Logistics LP, Bank of America, N.A., as administrative agent, and the other lenders party thereto	8-K	10.2	2/3/2016
10.4	Agreement and Consent, dated as of November 9, 2017, among Andeavor Logistics LP, certain subsidiaries of Andeavor Logistics LP party thereto, the lenders party thereto, and Bank of America, N.A., as Administrative Agent	8-K	10.2	11/13/2017
10.5	Support Agreement, dated as of April 6, 2015 by and among QEP Midstream Partners, LP, Tesoro Logistics LP, and QEP Field Services, LLC	8-K	10.1	4/6/2015

130 |

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.6	Fourth Amended and Restated Omnibus Agreement, dated as of October 30, 2017, among Andeavor, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Tesoro Logistics LP and Tesoro Logistics GP, LLC	8-K	10.2	10/31/2017
10.7	First Amended and Restated Schedules to the Fourth Amended and Restated Omnibus Agreement, dated as of November 8, 2017, by and among Andeavor, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Andeavor Logistics LP and Tesoro Logistics GP, LLC	8-K	10.1	11/8/2017
10.8	First Amended and Restated Secondment and Logistics Services Agreement, dated October 30, 2017, Andeavor Logistics, TLLP GP, Tesoro Logistics Operations LLC (“TLO”), Andeavor, WNRL, WNRLGP and their direct and indirect subsidiaries	8-K	10.3	10/31/2017
10.9	Transportation Services Agreement (High Plains Pipeline System), dated as of April 26, 2011, between Tesoro High Plains Pipeline Company LLC and Tesoro Refining and Marketing Company	8-K	10.6	4/29/2011
10.10	Second Amended and Restated Trucking Transportation Services Agreement, dated as of March 26, 2013, among Tesoro Logistics Operations, LLC and Tesoro Refining & Marketing Company LLC	8-K	10.1	4/1/2013
10.11	Second Amended and Restated Master Terminalling Services Agreement, dated as of May 3, 2013, among Tesoro Refining and Marketing Company LLC, Tesoro Alaska Company and Tesoro Logistics Operations LLC	10-Q	10.2	5/8/2013
10.12	Amendment No. 1 to the Second Amended and Restated Master Terminalling Services Agreement dated as of September 16, 2016, by and among Tesoro Refining and Marketing Company LLC, Tesoro Alaska Company LLC and Tesoro Logistics Operations LLC	8-K	10.1	9/22/2016
10.13	Amended and Restated Master Terminalling Services Agreement – Southern California, dated as December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.10	12/9/2013
10.14	Terminal Expansion Agreement, dated as of February 27, 2012, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	10-K	10.21	2/29/2012
10.15	Amended and Restated Transportation Services Agreement (Salt Lake City Short-Haul Pipelines), dated as of November 19, 2014, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.3	12/15/2014
10.16	Salt Lake City Storage and Transportation Services Agreement, dated as of April 26, 2011, between Tesoro Refining and Marketing Company and Tesoro Logistics Operations LLC	8-K	10.10	4/29/2011
10.17	Terminal Sublease, dated as of April 26, 2011, between Tesoro Alaska Company, as Landlord, and Tesoro Alaska Logistics LLC, as Tenant	8-K	10.11	4/29/2011
10.18	Amorco Marine Terminal Use and Throughput Agreement, effective April 1, 2012, between Tesoro Refining and Marketing Company and Tesoro Logistics Operations LLC	8-K	10.4	4/3/2012
10.19	Amended and Restated Long Beach Berth Access Use and Throughput Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.8	12/9/2013
10.20	Long Beach Berth Throughput Agreement, dated as of December 6, 2013, among Carson Cogeneration Company, Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.9	12/9/2013
10.21	Long Beach Operating Agreement, effective September 14, 2012, between Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Refining and Marketing Company	8-K	10.6	9/17/2012
10.22	Long Beach Storage Services Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.11	12/9/2013
10.23	Long Beach Pipeline Throughput Agreement (84/86 Pipelines), dated as of December 6, 2013, between the Operating Company and Tesoro Refining & Marketing Company LLC	8-K	10.13	12/9/2013
10.24	Transportation Services Agreement (Los Angeles Short-Haul Pipelines), effective September 14, 2012, among Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Refining and Marketing Company	8-K	10.7	9/17/2012

December 31, 2018 |131

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.25	Anacortes Track Use and Throughput Agreement, dated as of November 15, 2012, among Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining and Marketing Company and Tesoro Logistics Operations LLC	8-K	10.4	11/15/2012
10.26	Amendment No. 1 to Anacortes Track Use and Throughput Agreement, dated as of July 1, 2014, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.3	7/1/2014
10.27	Ground Lease, dated as of November 15, 2012, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.5	11/15/2012
10.28	First Amendment to Ground Lease, dated as of July 1, 2014, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.6	7/1/2014
10.29	Ground Lease dated as of July 1, 2014, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.7	7/1/2014
10.30	Right of First Refusal, Option Agreement and Agreement of Purchase and Sale, dated as of November 15, 2012, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.6	11/15/2012
10.31	Second Amended and Restated Representation and Services Agreement for Oil Spill Contingency Planning, Response and Remediation, dated as of September 16, 2016, by and among the subsidiaries of Andeavor and Andeavor Logistics LP party thereto	8-K	10.3	9/22/2016
10.32	Carson Storage Services Agreement, dated as of June 1, 2013, among Tesoro Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.5	6/3/2013
10.33	Carson Assets Indemnity Agreement, dated as of December 6, 2013, among Tesoro Corporation, Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.2	12/9/2013
10.34	Carson II Storage Services Agreement, dated as of November 12, 2015, by and between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.2	11/12/2015
10.35	Berth 121 Sublease Rights Agreement, dated as of December 6, 2013, among Carson Cogeneration Company, Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.3	12/9/2013
10.36	Berth 121 Operating Agreement, dated as of December 6, 2013, between Carson Cogeneration Company and Tesoro Logistics Operations LLC	8-K	10.4	12/9/2013
10.37	Terminal 2 Sublease Rights Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.5	12/9/2013
10.38	Terminals 2 and 3 Ground Lease Rights Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.6	12/9/2013
10.39	Terminals 2 and 3 Operating Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.7	12/9/2013
10.40	Transportation Services Agreement (SoCal Pipelines), dated as of December 6, 2013, between Tesoro Refining & Marketing Company LLC and Tesoro SoCal Pipeline Company LLC	8-K	10.12	12/9/2013
10.41	Amendment No. 1 to Transportation Services Agreement (SoCal Pipelines), dated as of November 12, 2015, among Tesoro SoCal Pipeline Company LLC and Tesoro Refining & Marketing Company LLC	8-K	10.3	11/12/2015
10.42	Carson Coke Handling Services Agreement, dated as of December 6, 2013, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.14	12/9/2013
10.43	Lease Agreement, dated as of December 6, 2013, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.19	12/9/2013
10.44	Sublease, dated as of December 9, 2013, by and between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	2.1	12/10/2013

132 |

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.45	Lease, dated as of January 11, 2012, by and between the City of Long Beach and Tesoro Refining & Marketing Company LLC	8-K	2.2	12/10/2013
10.46	License Agreement, dated as of November 12, 2015, among Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.4	11/12/2015
10.47	Construction Service Agreement - Anacortes Products Terminal, dated as of July 1, 2014, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	10-Q	10.1	8/1/2014
10.48	Terminalling Services Agreement – Nikiski, dated as of July 1, 2014, among Tesoro Alaska Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.1	7/1/2014
10.49	Terminalling Services Agreement – Anacortes, dated as of July 1, 2014, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Logistics Operations LLC	8-K	10.2	7/1/2014
10.50	Amendment No.1 to Terminalling Services Agreement - Anacortes, dated as of November 1, 2015, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	10-K	10.71	2/25/2016
10.51	Terminalling Services Agreement – Martinez, dated as of July 1, 2014, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP, and Tesoro Logistics Operations LLC	8-K	10.4	7/1/2014
10.52	Storage Services Agreement - Anacortes, dated as of July 1, 2014, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Logistics Operations LLC	8-K	10.5	7/1/2014
10.53	Martinez License Agreement, dated as of July 1, 2014, between Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.8	7/1/2014
10.54	Martinez Rights Agreement, dated as of July 1, 2014, among Tesoro Refining & Marketing Company LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Logistics Operations LLC	8-K	10.9	7/1/2014
10.55	Indemnification Agreement, dated as of December 2, 2014, between Tesoro Logistics LP and QEP Field Services Company	8-K	10.1	12/8/2014
10.56	Transition Services Agreement, dated as of December 2, 2014, between Tesoro Logistics LP and QEP Resources, Inc.	8-K	10.2	12/8/2014
10.57	Guaranty, dated as of December 2, 2014, by QEP Resources, Inc., in favor of Tesoro Logistics LP	8-K	10.3	12/8/2014
10.58	Intercompany Indemnity, Subrogation and Contribution Agreement, dated as of December 2, 2014, among Tesoro Logistics LP, QEP Midstream Partners, LP, QEP Midstream Partners Operating, LLC, QEPM Gathering I, LLC, Rendezvous Pipeline Company, LLC and Green River Processing, LLC	8-K	10.6	12/8/2014
10.59	Keep-Whole Commodity Fee Agreement, dated as of December 7, 2014, among Tesoro Refining & Marketing Company LLC, QEP Field Services, LLC, QEPM Gathering I, LLC and Green River Processing, LLC	8-K	10.9	12/8/2014
10.60	First Amendment to Keep-Whole Commodity Fee Agreement, dated as of February 1, 2016, among QEP Field Services, LLC, QEPM Gathering I, LLC, Green River Processing, LLC, and Tesoro Refining & Marketing Company LLC	8-K	10.3	2/3/2016
10.61	Agreement, dated effective as of February 19, 2016, between Tesoro Refining and Marketing Company LLC and Green River Processing, LLC, related to the back-to-back purchase and sale of waxy crude oil	10-K	10.82	2/25/2016
10.62	Ground Lease, dated as of July 1, 2016, between Tesoro Alaska Company LLC and Tesoro Logistics Operations LLC	8-K	10.1	7/7/2016
10.63	Kenai Storage Services Agreement, dated as of July 1, 2016, among Tesoro Alaska Company LLC, Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	8-K	10.3	7/7/2016
10.64	Alaska Terminalling Services Agreement, dated as of September 16, 2016 by and among Tesoro Alaska Company LLC, Tesoro Logistics Operations LLC, Tesoro Alaska Terminals LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	8-K	10.2	9/22/2016
10.65	Martinez Storage Services Agreement, dated as of November 21, 2016, by and among Tesoro Refining & Marketing Company LLC, Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	8-K	10.2	11/21/2016

December 31, 2018 |133

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.66	License Agreement, dated as of November 21, 2016, by and among Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.3	11/21/2016
10.67	Avon Marine Terminal Operating Agreement, dated as of November 21, 2016, by and among Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Refining & Marketing Company LLC	8-K	10.4	11/21/2016
10.68	Sublease, dated as of November 21, 2016, by and among Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.6	11/21/2016
10.69	Avon Marine Terminal Use and Throughput Agreement, dated as of November 21, 2016, by and among Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC, Tesoro Logistics LP and Tesoro Refining & Marketing Company LLC	8-K	10.7	11/21/2016
10.70	Renewal Trucking Transportation Services Agreement	10-Q	10.1	8/9/2017
10.71	Support Agreement, dated as of August 13, 2017, by and among Andeavor Logistics LP, Western Refining Logistics, LP, St. Paul Park Refining Co. LLC and Western Refining Southwest, Inc	8-K	10.1	8/14/2017
10.72	Sponsor Equity Restructuring Agreement, dated as of August 13, 2017 between Andeavor, Andeavor Logistics LP, and Tesoro Logistics GP, LLC	8-K	10.2	8/14/2017
10.73	Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC (incorporated by reference herein to Exhibit 10.6 to WNRL’s Current Report on Form 8-K filed on October 22, 2013, File No. 1-36114)
10.74	Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference herein to Exhibit 10.5 to WNRL’s Current Report on Form 8-K filed on October 22, 2013, File No. 1-36114)
10.75	Amendment No. 1 to Pipeline and Gathering Services Agreement, dated as of October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC (incorporated by reference herein to Exhibit 10.1 to WNRL’s Current Report on Form 8-K filed on November 2, 2015, File No. 1-36114)
10.76	Crude Oil Trucking Transportation Services Agreement, dated October 15, 2014, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P. and Western Refining Southwest, Inc. (incorporated by reference herein to Exhibit 10.3 to WNRL’s Current Report on Form 8-K filed on October 16, 2014, File No. 1-36114)
10.77	Fuel Distribution and Supply Agreement, dated October 15, 2014, by and between Western Refining Wholesale, LLC and Western Refining Southwest, Inc. (incorporated by reference herein to Exhibit 10.2 to WNRL’s Current Report on Form 8-K filed on October 16, 2014, File No. 1-36114)
10.78	Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC (incorporated by reference herein to Exhibit 10.1 to WNRL’s Current Report on Form 8-K filed on October 16, 2014, File No. 1-36114)
10.79	Asphalt Trucking Transportation Services Agreement, dated May 4, 2016 and effective as of January 1, 2016, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P., and, for certain limited purposes stated therein, Western Refining Southwest, Inc. (incorporated by reference herein to Exhibit 10.1 to WNRL’s Quarterly Report on Form 10-Q filed on August 4, 2016, File No. 1-36114)
10.80	Terminalling, Transportation and Storage Services Agreement, dated September 15, 2016, by and between St. Paul Park Refining Co. LLC and Western Refining Terminals, LLC (incorporated by reference herein to Exhibit 10.1 to WNRL’s Current Report on Form 8-K filed on September 20, 2016, File No. 1-36114)
10.81	Anacortes II Storage Services Agreement, dated as of November 8, 2017, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.2	11/8/2017
10.82	Transportation Services Agreement (Anacortes Short Haul Pipelines), dated as of November 8, 2017, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.3	11/8/2017

134 |

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.83	Anacortes Manifest Rail Terminalling Services Agreement, dated as of November 8, 2017, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.4	11/8/2017
10.84	Anacortes Marine Terminal Operating Agreement, dated as of November 8, 2017, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.5	11/8/2017
10.85	Sublease Rights and Escrow Agreement, dated as of November 8, 2017, among Andeavor Logistics LP, Tesoro Logistics GP, LLC, Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	8-K	10.6	11/8/2017
10.86	Ground Lease, dated as of November 8,2017, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.7	11/8/2017
10.87	First Amendment to Ground Lease (Anacortes Crude Storage Facility), dated as of November 8,2017, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.8	11/8/2017
10.88	Second Amendment to Ground Lease, dated as of November 8,2017, between Tesoro Logistics Operations LLC and Tesoro Refining and Marketing Company	8-K	10.9	11/8/2017
†10.89	Andeavor Logistics LP 2011 Long-Term Incentive Plan, as amended and restated	10-K	10.88	2/21/2018
†10.90	Form of Tesoro Logistics LP 2011 Long-Term Incentive Plan Phantom Unit Award (Employee time-vesting awards)	S-1 (File No. 333-171525)	10.17	1/4/2011
†10.91	Form of Tesoro Logistics LP 2011 Long-Term Incentive Plan Phantom Unit Award (Non-employee director awards)	10-K	10.90	2/21/2018
†10.92	Form of Tesoro Logistics LP 2011 Long-Term Incentive Plan Performance Phantom Unit Agreement	8-K	10.1	2/22/2017
†10.93	Tesoro Logistics LP 2017 Grant of Performance-Vesting Phantom Units and Tandem DERs Term Sheet	8-K	10.2	2/22/2017
†10.94	Form of Tesoro Logistics LP 2011 Long-Term Incentive Plan Performance Phantom Unit Agreement (Employee performance-based awards granted in 2015)	8-K	10.1	2/18/2015
†10.95	Tesoro Logistics LP 2015 Grant of Performance-Vesting Phantom Units and Tandem DERs Term Sheet (Employee performance-based awards granted in 2015)	8-K	10.2	2/18/2015
†10.96	Form of Tesoro Logistics LP 2011 Long-Term Incentive Plan Performance Phantom Unit Agreement (Employee performance-based awards granted in 2016)	8-K	10.1	2/11/2016
†10.97	Tesoro Logistics LP 2016 Grant of Performance-Vesting Phantom Units and Tandem DERs Term Sheet (Employee performance-based awards granted in 2016)	8-K	10.2	2/11/2016
†10.98	Amended and Restated QEP Midstream Partners, LP 2013 Long-Term Incentive Plan	8-K	10.1	7/23/2015
†10.99	Description of 2015 Incentive Compensation Program	10-K	10.15	2/24/2015
†10.100	Description of 2016 Incentive Compensation Program	10-K	10.20	2/25/2016
†10.101	Andeavor Logistics LP Non-Employee Director Compensation Program (2018)	10-K	10.100	2/21/2018
†10.102	Amended and Restated Andeavor Executive Severance and Change in Control Plan effective May 1, 2013	10-K	10.101	2/21/2018
†10.103	Form of indemnification agreement between Tesoro Logistics GP, LLC and the independent members of its board of directors	8-K	10.1	12/15/2014
†10.104	Form of indemnification agreement between Tesoro Corporation and members of its management who may serve as directors or executive officers of Tesoro Logistics GP, LLC	8-K	10.3	8/4/2008
10.105	Amendment No. 1 to Third Amended and Restated Credit Agreement, dated as of January 5, 2018, among Andeavor Logistics LP, certain subsidiaries of Andeavor Logistics LP party thereto, the lenders party thereto, and Bank of America, N.A.	8-K	10.1	1/5/2018
10.106	Amendment No. 1 to Credit Agreement, dated as of January 5, 2018, among Andeavor Logistics LP, certain subsidiaries of Andeavor Logistics LP party thereto, the lenders party thereto, and Bank of America, N.A.	8-K	10.2	1/5/2018

December 31, 2018 |135

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.107	Form of Andeavor Logistics LP 2011 Long-Term Incentive Plan Performance Phantom Unit Agreement	8-K	10.1	2/23/2018
10.108	Andeavor Logistics LP 2018 Grant of Performance-Vesting Phantom Units and Tandem DERs Term Sheet	8-K	10.2	2/23/2018
10.109	Term Sheet for 2018 Performance Phantom Unit Award (Employee)	8-K	10.2	2/23/2018
10.110	First Amendment to Storage Services Agreement - Anacortes II, dated January 1, 2018	10-Q	10.1	5/8/2018
10.111	Amendment No. 1 to Kenai Storage Services Agreement, dated as of July 1, 2016, among Tesoro Alaska Company LLC, Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	10-Q	10.1	8/7/2018
10.112	Amendment No. 1 to Avon Marine Terminal Use and Throughput Agreement, dated as of January 1, 2017, by and among Tesoro Refining & Marketing Company LLC and Tesoro Logistics Operations LLC	10-Q	10.2	8/7/2018
10.113	Amendment No. 1 to Martinez Storage Services Agreement, dated as of November 21, 2016, by and among Tesoro Refining & Marketing Company LLC, Tesoro Logistics Operations LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	10-Q	10.3	8/7/2018
10.114	Amendment No. 1 to Alaska Terminalling Services Agreement, dated as of September 16, 2016 by and among Tesoro Alaska Company LLC, Tesoro Logistics Operations LLC, Tesoro Alaska Terminals LLC, Tesoro Logistics GP, LLC and Tesoro Logistics LP	10-Q	10.4	8/7/2018
10.115	Amendment No. 1 to Crude Oil Trucking Transportation Services Agreement, dated October 15, 2014, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P. and Western Refining Southwest, Inc.	10-Q	10.5	8/7/2018
10.116	Amendment No. 2 to Crude Oil Trucking Transportation Services Agreement, dated October 15, 2014, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P. and Western Refining Southwest, Inc.	10-Q	10.6	8/7/2018
10.117	Amendment No. 1 to Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC	10-Q	10.7	8/7/2018
10.118	Amendment No. 2 to Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC	10-Q	10.8	8/7/2018
10.119	Amendment No. 3 to Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC	10-Q	10.9	8/7/2018
10.120	Amendment No. 4 to Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC	10-Q	10.10	8/7/2018
10.121	Amendment No. 5 to Product Supply Agreement, dated October 15, 2014, by and among Western Refining Southwest, Inc., Western Refining Company, L.P. and Western Refining Wholesale, LLC	10-Q	10.11	8/7/2018
10.122	Amendment No. 1 to Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC	10-Q	10.12	8/7/2018
10.123	Amendment No. 2 to Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC	10-Q	10.13	8/7/2018
10.124	Amendment No. 3 to Terminalling, Transportation and Storage Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Terminals, LLC	10-Q	10.14	8/7/2018
10.125	Amendment No. 1 to Terminalling, Transportation and Storage Services Agreement, dated September 15, 2016, by and between St. Paul Park Refining Co. LLC and Western Refining Terminals, LLC	10-Q	10.15	8/7/2018
10.126	Amendment No. 2 to Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC	10-Q	10.16	8/7/2018

136 |

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.127	Amendment No. 3 to Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC	10-Q	10.17	8/7/2018
10.128	Amendment No. 4 to Pipeline and Gathering Services Agreement, dated October 16, 2013, by and among Western Refining Company, L.P., Western Refining Southwest, Inc. and Western Refining Pipeline, LLC	10-Q	10.18	8/7/2018
10.129	Amendment No. 1 to Asphalt Trucking Transportation Services Agreement, dated June 29, 2018 and effective as of January 1, 2016, by and among Western Refining Wholesale, LLC, Western Refining Company, L.P., and, for certain limited purposes stated therein, Western Refining Southwest, Inc.	10-Q	10.19	8/7/2018
10.130	Amendment No. 1 to Fuel Distribution and Supply Agreement, dated October 15, 2014, by and between Western Refining Wholesale, LLC and Western Refining Southwest, Inc.	10-Q	10.20	8/7/2018
10.131	Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement, dated as of August 6, 2018, by and among Andeavor, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Andeavor Logistics LP and Tesoro Logistics GP, LLC.	8-K	10.1	8/7/2018
10.132	Master Terminalling Services Agreement, dated as of August 6, 2018, by and among Tesoro Refining & Marketing Company LLC, Western Refining Southwest, Inc., Western Refining Company, LP, St. Paul Park Refining Co. LLC, Tesoro Logistics Operations LLC, Tesoro Great Plains Gathering & Marketing LLC and Western Refining Terminals, LLC.	8-K	10.2	8/7/2018
10.133	Construction Service Agreement, dated as of August 6, 2018, by and between Tesoro SoCal Pipeline Company LLC and Tesoro Refining & Marketing Company LLC.	8-K	10.3	8/7/2018
10.134	Transportation Services Agreement, dated as of August 6, 2018, by and between Tesoro SoCal Pipeline Company LLC and Tesoro Refining & Marketing Company LLC.	8-K	10.4	8/7/2018
10.135	Master Unloading and Storage Agreement, dated as of August 6, 2018, by and between Western Refining Pipeline, LLC and Western Refining Company, L.P.	8-K	10.5	8/7/2018
10.136	Asphalt Terminalling, Transportation and Storage Services Agreement, dated as of August 6, 2018, between Western Refining Company, L.P. and Asphalt Terminals LLC.	8-K	10.6	8/7/2018
10.137	First Amendment to Master Terminalling Services Agreement, effective August 6, 2018, by and among Tesoro Refining & Marketing Company LLC, Western Refining Southwest, Inc., Western Refining Company, LP, St. Paul Park Refining Co. LLC, Tesoro Logistics Operations LLC, Tesoro Great Plains Gathering & Marketing LLC and Western Refining Terminals, LLC	10-Q	10.4	11/7/2018
10.138	First Amendment to Asphalt Terminalling, Transportation and Storage Services Agreement, effective August 6, 2018, between Western Refining Company, L.P. and Asphalt Terminals LLC	10-Q	10.9	11/7/2018
10.139	Terminal Services Agreement, dated as of January 1, 2017, between Tesoro Great Plains Gathering & Marketing LLC and Tesoro Refining & Marketing Company LLC	10-Q	10.10	11/7/2018
10.140	First Amendment to Terminal Services Agreement, effective August 6, 2018, between Tesoro Great Plains Gathering & Marketing LLC and Tesoro Refining & Marketing Company LLC	10-Q	10.11	11/7/2018
10.141	Third Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement, effective August 6, 2018, by and among Andeavor, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Andeavor Logistics LP and Tesoro Logistics GP, LLC	10-Q	10.2	11/7/2018
10.142	Amendment No. 2 to Third Amended and Restated Credit Agreement, dated as of December 20, 2018, among Andeavor Logistics LP, as borrower, certain of its subsidiaries party thereto, as guarantors, the lenders party thereto, and Bank of America, N.A., as administrative agent	8-K	10.1	12/27/2018
10.143	Amendment No. 2 to the Credit Agreement, dated as of December 20, 2018, among Andeavor Logistics LP, as borrower, certain of its subsidiaries party thereto, as guarantors, the lenders party thereto, and Bank of America, N.A., as administrative agent	8-K	10.2	12/27/2018
10.144	Loan Agreement, dated as of December 21, 2018, by and between Andeavor Logistics LP and Marathon Petroleum Corporation	8-K	10.3	12/27/2018

December 31, 2018 |137

Exhibits and Financial Statement Schedules

		Incorporated by Reference (File No. 1-35143, unless otherwise indicated)
Exhibit Number	Description of Exhibit	Form	Exhibit	Filing Date
10.145	Secondment Agreement, dated as of January 30, 2019, by and among Marathon Refining Logistics Services, LLC, Andeavor Logistics LP, Tesoro Logistics GP, LLC and certain other parties thereto	8-K	10.1	2/5/2019
10.146	Secondment Agreement, dated as of January 30, 2019, by and among Marathon Petroleum Logistics Services, LLC, Andeavor Logistics LP, Tesoro Logistics GP, LLC and certain other parties thereto	8-K	10.2	2/5/2019
*10.147	First Amendment to Fourth Amended and Restated Omnibus Agreement, dated as of January 30, 2019, among Andeavor LLC, Marathon Petroleum Company LP, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Andeavor Logistics LP and Tesoro Logistics GP, LLC
*†10.148	S. Sterin Award Amendment, effective as of October 3, 2018
*†10.149	D. Sorensen Award Amendment, effective as of October 3, 2018
*†10.150	Tesoro Logistics GP, LLC Non-Management Director Compensation Policy and Director Equity Award Terms
*21.1	Subsidiaries of the Company
*23.1	Consent of Independent Registered Public Accounting Firm (Ernst & Young LLP)
*24.1	Power of Attorney of Directors and Officers of Tesoro Logistics GP, LLC
*31.1	Certification by Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification by Principal 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 Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**101.INS	XBRL Instance Document
**101.SCH	XBRL Taxonomy Extension Schema Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

*    Filed herewith

**    Submitted electronically herewith

†    Compensatory plan or arrangement

‡ Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Andeavor agrees to furnish a copy of such schedules, or any section thereof, to the SEC upon request.

Copies of exhibits filed as part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct any inquiries to the Corporate Secretary, Andeavor Logistics LP, 200 East Hardin Street, Findlay, Ohio 45840.

Item 16. Form 10-K Summary

Not applicable.

138 |

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date:	February 28, 2019	Andeavor Logistics LP
		By:	Tesoro Logistics GP, LLC
			Its General Partner
		By:	/s/ D. ANDREW WOODWARD
			D. Andrew Woodward
			Vice President, Finance
			(Principal Financial Officer and Duly Authorized Signatory)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 28, 2019 on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title
/s/ GARY R. HEMINGER	Chairman of the Board of Directors and Chief Executive Officer
Gary R. Heminger	(Principal Executive Officer)
/s/ D. ANDREW WOODWARD	Vice President, Finance
D. Andrew Woodward	(Principal Financial Officer)
/s/ BLANE W. PEERY	Vice President, Accounting & Systems Integration
Blane W. Peery	(Principal Accounting Officer)
*	Director
Pamela K. M. Beall
*	Director
Sigmund L. Cornelius
*	Director
Ruth I. Dreessen
*	Director
Gregory J. Goff
*	Director
Timothy T. Griffith
*	Director
Michael J. Hennigan
*	Director
James H. Lamanna
*	Director
Frank M. Semple
*	Director
Donald C. Templin

December 31, 2018 |139

* The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the registrant, which is being filed herewith on behalf of such directors and officers.

By:	/s/ GARY R. HEMINGER	February 28, 2019
	Gary R. Heminger
	Attorney-in-Fact

140 |