Document

 

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
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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
Important Information Regarding Forward-Looking Statements
Part I
Item 1 Business
 
Terminalling and Transportation
 
Gathering and Processing
 
Wholesale
 
Rate and Other Regulations
 
Environmental Regulations
Item 1A Risk Factors
Item 1B Unresolved Staff Comments
Item 2 Properties
Item 3 Legal Proceedings
Item 4 Mine Safety Disclosures
Part II
Item 5 Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6 Selected Financial Data
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Business Strategy and Overview
 
Results of Operations
 
Capital Resources and Liquidity
 
Accounting Standards
Item 7A Quantitative and Qualitative Disclosures about Market Risk
Item 8 Financial Statements and Supplementary Data
 
Consolidated Statements of Operations
 
Consolidated Balance Sheets
 
Consolidated Statements of Partner’s Equity
 
Consolidated Statements of Cash Flows
 
Notes to Consolidated Financial Statements
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A Controls and Procedures

 
Part III
 
Item 10 Directors, Executive Officers and Corporate Governance
Item 11 Executive Compensation
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13 Certain Relationships and Related Transactions, and Director Independence
Item 14 Principal Accountant Fees and Services
Part IV
 
Item 15 Exhibits and Financial Statement Schedules
Item 16 Form 10-K Summary
Signatures







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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 ended December 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.


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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.

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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:
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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.


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Business

Commercial Agreements

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

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(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.

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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.


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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.


 
 
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http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12743871&doc=20 http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12743871&doc=21 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

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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.

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12743871&doc=19 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

 
 
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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

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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

 
 
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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

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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.


 
 
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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

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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

 
 
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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

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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.


 
 
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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.


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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;

 
 
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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.


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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 billion aggregate 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.


 
 
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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

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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.


 
 
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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

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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

 
 
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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

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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.


 
 
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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.


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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

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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.


 
 
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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.


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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.


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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;

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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.


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Management’s Discussion and Analysis

Consolidated Results

Highlights (in millions)

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(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


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Management’s Discussion and Analysis

2018 Versus 2017

Net Earnings Reconciliation (in millions)

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Overview
Our net earnings for 2018 increased $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 2018 decreased $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.


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Management’s Discussion and Analysis

2017 Versus 2016

Net Earnings Reconciliation (in millions)

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Overview
Our net earnings for 2017 increased $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 2017 increased $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.


 
 
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Management’s Discussion and Analysis

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

Highlights (in millions)

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

Terminalling and Transportation Segment Operating Data

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

Volumes
Terminalling throughput increased 307 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 increased 110 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 increased 448 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 increased 34 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.


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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

Average pipeline transportation 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.


 
 
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Management’s Discussion and Analysis

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

Highlights (in millions)

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

Gathering and Processing Segment Operating Data

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(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 increased 2.1 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 decreased 200 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 increased 65 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 increased 0.8 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 increased 84 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 increased 108 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.

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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.


 
 
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Management’s Discussion and Analysis

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

Highlights (in millions)

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(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.


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Management’s Discussion and Analysis

Non-GAAP Reconciliations

Reconciliation of Net Earnings to EBITDA (in millions)

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(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.


 
 
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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.

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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