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, 2017
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.)
 
 
19100 Ridgewood Pkwy, San Antonio, Texas 78259-1828
(Address of principal executive offices) (Zip Code)
210-626-6000
(Registrant’s telephone number, including area code)
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 þ No o
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer
þ
 
Accelerated filer
o
 
 
Non-accelerated filer
o (Do not check if a smaller reporting company)
 
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, 2017, 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 217,164,424 common units outstanding at February 15, 2018.

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
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 Accounting 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 in our discussion of the business and operating results:

AB 197 - Assembly Bill 197.

AICPA - American Institute of Certified Public Accountants.

ARO - Asset retirement obligations.

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, 2017 and 2015, 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.

BLM - Bureau of Land Management.

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.

Dropdown Credit Facility - Secured 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.

FASB - Financial Accounting Standards Board.

FERC - Federal Energy Regulatory Commission.

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 hydrocarbon.

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.

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.

IRS - Internal Revenue Service.

Mbpd - Thousand barrels per day.

MMBtu - Million British thermal units.

MMBtu/d - Million British thermal units per day.

MMcf - Million cubic feet. Cubic foot or feet 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.

NAAQS - National Ambient Air Quality Standards.


 
 
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Glossary of Terms

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.

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

OSRO - Oil Spill Response Organizations.

PCAOB - Public Company Accounting Oversight
Board.

PHMSA - The Pipeline and Hazardous Materials Safety Administration.

POP - Percent of Proceeds.

ppb - parts per billion.

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.

 
Revolving Credit Facility - Secured revolving credit facility.

RFS2 - Second Renewable Fuels Standard.

RGS - Rendezvous Gas Services, L.L.C.

SB 32 - 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.

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

TRC - Texas Railroad Commission.

Treasury Regulation - U.S. Treasury Regulation.

TRG - Three Rivers Gathering, L.L.C.

UBFS - Uintah Basin Field Services, L.L.C.

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.


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Business

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 Securities Exchange Act of 1934, 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:

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;
changes in global economic conditions on our business, on the business of our key customers, including Andeavor, 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, including Andeavor, 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, including Andeavor and Andeavor’s customers, and the ability to replace such contracts and/or customers;
the suspension, reduction or termination of Andeavor’s obligations under our commercial agreements and our secondment agreement;
a material change in profitability among our customers, including Andeavor;
 
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, including Andeavor, or the areas in which our customers operate;
disruptions due to equipment interruption or failure at our facilities, Andeavor’s facilities or third-party facilities on which our key customers, including Andeavor, 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;
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 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 Andeavor;
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 “Andeavor” or our “Sponsor” refer collectively to Andeavor and any of its subsidiaries, other than Andeavor Logistics, its subsidiaries and its general partner.

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 LP (formerly Tesoro Logistics LP and referred to herein as “Andeavor Logistics” or the “Partnership”) is a leading growth-oriented, full-service, and diversified midstream company operating in the western and mid-continent regions of the United States. We were formed by Andeavor (formerly Tesoro Corporation) and its wholly-owned subsidiary, Tesoro Logistics GP, LLC (“TLGP”), our general partner, in December 2010 as a Delaware master limited partnership to own, operate, develop and acquire logistics assets. Following the name change on August 1, 2017, 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 Andeavor’s refineries:
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Business

2017 Acquisitions

WNRL Merger
Effective October 30, 2017, Andeavor Logistics merged with Western Refining Logistics, LP (“WNRL”) by exchanging all outstanding common units of WNRL with units of Andeavor Logistics (the “WNRL Merger”). Refer to our discussion of the WNRL Merger, including financial details relating to the WNRL Merger and concurrent equity restructuring of our general partner and IDR interests 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. With the WNRL Merger, Andeavor Logistics expanded its asset base and operations as follows:

705 miles of pipelines located in Permian Basin area of west Texas and southern New Mexico that gather and transport crude oil by pipeline, as well as by truck, from various production locations to Andeavor’s El Paso, Texas and Gallup, New Mexico refineries;
12.4 million barrels of storage capacity, including approximately 11.4 million barrels of crude oil, feedstock, blendstock, refined product and asphalt storage tanks near Andeavor’s El Paso, Gallup and St. Paul Park, Minnesota refineries and approximately 1.0 million barrels of crude oil storage tanks located along the gathering pipeline systems discussed above; and
Wholesale fuel distribution business that purchases, sells, and transports gasoline and diesel to Andeavor’s retail sites or third parties.

As of December 31, 2017, integration of these assets and operations continues. However, the financial results for these WNRL assets have been included with the Partnership’s consolidated and segment operating results for 2017 on a recast basis back to June 1, 2017, the date of Andeavor’s acquisition of WNRL’s former parent, Western Refining, Inc. Refer to our discussion of each segment below for an understanding how WNRL’s assets and operations have been integrated with Andeavor Logistics’ existing operations. The wholesale fuel distribution business is a new business line for us and is separately presented in the new Wholesale segment.

Anacortes Logistics Assets Acquisition
On November 8, 2017, we acquired from a subsidiary of Andeavor certain logistics assets located in Anacortes, Washington (the “Anacortes Logistics Assets”), that included 3.9 million barrels of storage for crude oil, feedstock and refined products at Andeavor’s Anacortes Refinery, the Anacortes marine terminal with 73 Mbpd of feedstock and refined product throughput, a manifest rail facility with 4 thousand barrels of throughput and crude oil and refined products pipelines with 111 Mbpd of throughput combined.

North Dakota Gathering and Processing Assets
On January 1, 2017, we acquired crude oil, natural gas and produced water gathering systems and two natural gas processing facilities (the “North Dakota Gathering and Processing Assets”) from Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Energy Midstream, LLC. The North Dakota Gathering and Processing Assets include over 650 miles of crude oil, natural gas, and produced water gathering pipelines, 170 MMcf per day of natural gas processing capacity and 18.7 Mbpd of fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. With this acquisition, we expanded the assets in our Gathering and Processing segment located in the Williston Basin area of North Dakota to further grow our integrated, full-service logistics capabilities in support of third-party demand for crude oil, natural gas and water gathering services as well as natural gas processing services. In addition, this extends our capacity and capabilities by adding new origin and destination points for our common carrier pipelines in North Dakota and extends our crude oil, natural gas and water gathering and associated gas processing footprint to enhance and improve overall basin logistics efficiencies.

Commercial Agreements

Percentage of Affiliate and Third-Party Revenues by Operating Segment during 2017

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Business

Andeavor

Andeavor accounted for $1.4 billion, or 44%, of our total revenues in the year ended December 31, 2017.

We process gas for certain producers under keep-whole processing agreements. Under a keep-whole agreement, normally a producer would transfer title of the NGLs produced during gas processing and the processor, in exchange, would deliver to the producer natural gas with a BTU content equivalent to the NGLs that would be removed. However, Andeavor Logistics entered into an agreement with Andeavor, which transfers the commodity risk exposure associated with these keep-whole processing agreements from Andeavor Logistics to Andeavor (the “Keep-Whole Commodity Agreement”). Under the Keep-Whole Commodity Agreement, Andeavor pays Andeavor Logistics a processing fee for NGLs related to keep-whole agreements and delivers the replaced natural gas to the producers on behalf of Andeavor Logistics. Andeavor Logistics pays Andeavor 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.

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

Third-Parties

Third-party revenues accounted for $1.8 billion, or 56%, of our total revenues for the year ended December 31, 2017.

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 an available revolving line of credit 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, 2017, we directly employed 518 employees through our wholesale subsidiary. The remainder of our employees that conduct our business are employed by our general partner and its affiliates. We had over 1,900 employees performing services for our operations as of December 31, 2017, approximately 250 of whom are covered by collective bargaining agreements that expire on February 1, 2019.

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://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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Business

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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
Land Terminals
44
AK, AZ, CA, ID, MN, NM, TX, UT, WA
Crude Oil, Refined Products, Asphalt
Andeavor, Third-Party
1,263

44,957


Marine Terminals
6
CA, WA
Crude Oil, Refined Products
Andeavor, Third-Party
955

2,900


Northwest Products System
ID, UT, WA
Refined Products
Andeavor, Third-Party


1,201

Southern California System
CA
Crude Oil, Natural Gas, Refined Product
Andeavor, Third-Party


216

Kenai Pipeline
AK
Refined Products
Andeavor


74

Salt Lake City Short-haul
UT
Crude Oil, Refined Products
Andeavor


22

Petroleum Coke Handling (a)
1
CA
Petroleum Coke
Andeavor



 
51
 
 
 
2,218

47,857

1,513


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

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

providing storage services;
transporting refined products;
delivering crude oil, refined products and intermediate feedstocks from vessels to refineries and terminals;
loading and unloading crude oil transported by unit train to Andeavor’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 Andeavor’s Los Angeles refinery.

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, 2017, approximately 90% 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.

Andeavor is our largest customer. We derived 92% of Terminalling and Transportation revenues from Andeavor and its affiliates, most of which were derived from contracts that include minimum volume commitments, and have provided approximately 43.1 million barrels of dedicated storage capacity for Andeavor under various agreements.

WNRL Assets and Operations

Through the WNRL Merger and the realignment of our operating segments discussed in Items 7 and 8, the Terminalling and Transportation segment includes the following WNRL assets and related operations included in the table above:

Refined products terminals located in El Paso, Texas; Albuquerque, Bloomfield and Gallup, New Mexico; and St. Paul Park, Minnesota. The terminals distribute refined products supplied by an Andeavor refinery through truck loading racks, barge facilities, rail and other logistics assets;
Storage facilities located in El Paso, Gallup and St. Paul Park. Each facility is located adjacent to an Andeavor refinery and provides storage and transfer services required to support the refinery’s operations; and
Asphalt terminalling and processing services at our asphalt plant and terminal in El Paso, as well as at three stand-alone asphalt terminals in Albuquerque and Phoenix and Tucson, Arizona. Our El Paso asphalt plant is located adjacent to Andeavor’s El Paso refinery. We also operate a fleet of asphalt trucks, which are utilized to deliver asphalt to Andeavor's asphalt terminals and third-party customers.


 
 
December 31, 2017 | 7

Business

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 Andeavor and third-party customers as other terminals and pipelines may be able to supply Andeavor’s refineries or end user markets on a more competitive basis, due to terminal location, price, versatility and services provided. If Andeavor’s customers reduced their purchases of refined products from Andeavor due to the increased availability of less expensive product from other suppliers or for other reasons, Andeavor 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 USCG Transportation 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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Our Gathering and Processing segment consists of the following assets and operations:
System
Location
Key Products Handled
Volume Source
Processing Throughput Capacity (a)
(MMcf/d)
Pipeline
Mileage (b)
High Plains
MT, ND
Crude Oil
Andeavor, Third-Party

1,035

Southwest
NM, TX
Crude Oil
Andeavor, Third-Party

913

North Dakota
ND
Crude Oil, Natural Gas, Produced Water
Andeavor, Third-Party
170

780

Uinta Basin
UT
Natural Gas
Andeavor, Third-Party
650

635

Green River
WY
Crude Oil, Natural Gas
Andeavor, Third-Party
850

587

Vermillion
CO, UT, WY
Natural Gas
Third-Party
57

482

 
 
 
 
1,727

4,432


(a)
We have fractionation throughput capacity at our Blacks Fork complex, Robinson Lake complex and Belfield complex of 15.0 Mbpd, 11.5 Mbpd and 7.2 Mbpd, respectively.
(b)
The pipeline mileage associated with our equity method investments is not included in the table. Our equity method investments are discussed below.

We generate gathering and processing 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 and percentage-of-proceeds agreements.

Certain equity method investments that contribute to our gathering and processing systems including investments in:

RGS which operates the infrastructure that transports gas along 333 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 78 miles of gathering pipeline and gas compression assets located in the southeastern Uinta Basin.

We derived 24% of Gathering and Processing revenues from Andeavor and its affiliates. We process gas for certain producers under keep-whole processing agreements. Approximately 23% of our processing throughput capacity is currently supported by long-term, fee-based processing agreements with minimum volume commitments.

WNRL Assets and Operations

Through the WNRL Merger and the realignment of our operating segments discussed in Items 7 and 8, the Gathering and Processing segment includes the following WNRL assets and related operations included in the table above:

Four Corners System - A pipeline system which includes pipelines in Northwestern New Mexico that gather and transport crude oil and condensate produced in the Four Corners area and deliver it to Andeavor’s Gallup refinery or to the TexNew Mex pipeline system. This Four Corners area crude oil is received at our Bloomfield terminal and at crude oil stations we own located in Bisti, Lybrook, Pettigrew and Star Lake, New Mexico;
Permian Basin System - A pipeline system which includes the Delaware Basin system and other crude oil gathering assets in West Texas. It consists of 39 miles of pipelines located in Southeast New Mexico and West Texas and handles crude oil produced in the Delaware Basin. The system includes other crude gathering assets in West Texas that handle crude oil produced in the Permian Basin. The TexNew Mex pipeline extends 299 miles from our Four Corners system to the Delaware Basin; and
Crude Trucking - A fleet of crude oil trucks, which are utilized to gather, transport and deliver crude oil from collection points in Colorado, New Mexico and Utah to Andeavor’s El Paso and Gallup refineries and their interconnected pipelines.


 
 
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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. Condensate sales, however, tend to increase in the first quarter of each year, as the colder ground causes more condensates to fall out of the gas stream in our gathering system. However, this impact is minimal and we expect such seasonality to diminish as we continue to expand our existing assets or acquire additional assets outside of the affected areas.

Competition

Our common carrier crude oil gathering and transport systems consist of common carrier pipelines in North Dakota and Montana (“High Plains System”) and common carrier pipelines in New Mexico and Texas (“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 Shale/Williston Basin area of North Dakota and Montana (“Bakken Region”) and the Delaware and Midland Basins (“Southwest Region”), 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 and Southwest Regions. 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 Andeavor under our High Plains transportation services agreement (the “High Plains Pipeline Transportation Services Agreement”), Southwest pipeline and gathering services agreement (the “Southwest Pipeline and Gathering Services Agreement”) and our connection to Andeavor’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=12074155&doc=18 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 Andeavor's refining segment and from third-party suppliers. We have entered into a product supply agreement, as amended, with Andeavor and certain of its affiliates, pursuant to which Andeavor has agreed to sell, and we have agreed to buy, between 90% and 110% of 79 Mbpd of Andeavor’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. Andeavor 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 Andeavor, our principal customers are retail fuel distributors and the mining, construction, utility, manufacturing, transportation, aviation and agricultural industries. Our sales and services to Andeavor generally accounted for 31% of our fuel sales volumes for the year ended December 31, 2017.

As part of this fuel distributions business, we have entered into a fuel distribution and supply agreement with Andeavor. Under this arrangement, we are required to sell and deliver to Andeavor, and Andeavor is required to purchase and accept delivery

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from us, approximately 21 Mbpd of branded and unbranded motor fuels to Andeavor retail and cardlock locations in the Southwest. In exchange for the sale and delivery of branded and unbranded motor fuels, Andeavor 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 Andeavor fails to purchase the committed volume of branded and unbranded motor fuels, Andeavor will pay $0.03 per gallon for each gallon below the committed volume. Andeavor 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.

Rate and Other Regulations

General Interstate Regulation
Our High Plains Pipeline, Northwest Products Pipeline, Four Corners system, Permian Basin 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 Products Pipeline 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 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 Products Pipeline are grandfathered. The FERC allows for an annual rate change under its indexing methodology, which applies to transportation on our High Plains Pipeline and Northwest Products Pipeline.

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 Company, LLC (“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 Products Pipeline as common carriers pursuant to tariffs filed with the FERC, the NDPSC for the High Plains Pipeline, the NMPRC for the Four Corners system and the TRC and NMPRC for the Permian Basin system. The High Plains Pipeline offers tariffs from various locations in Montana and North Dakota to a variety of destinations, which are utilized by Andeavor and various third parties. Andeavor has historically shipped the majority of the volumes transported on the High Plains Pipeline, which is expected to continue in 2018. The Northwest Products Pipeline extends from Salt Lake City, Utah to Spokane, Washington and offers tariffs from various locations to a variety of destinations,

 
 
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which serves both third-party customers and Andeavor. 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. Andeavor 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 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 Fourth Amended and Restated Omnibus Agreement (“Amended Omnibus Agreement”) and the Carson Assets Indemnity Agreement, Andeavor 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 Andeavor. See Note 10 to our consolidated financial statements in Part II, 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

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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.

On October 1, 2015, EPA strengthened the NAAQS for ground-level ozone to 70 ppb 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 was enacted into federal law in December 2007 creating 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 Andeavor and our other customers. On October 22, 2015, the EPA finalized amendments to the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program, including adding a new Onshore Petroleum and Natural Gas Gathering and Boosting segment, which will include greenhouse gas emissions from equipment and sources within the petroleum and natural gas gathering and boosting systems. In September 2015, the EPA announced proposed new source performance standards for methane (a greenhouse gas) for new and modified oil and gas sector sources. These and other legislative regulatory measures will impose additional burdens on our business and those of Andeavor 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, the 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 Andeavor to the extent the release occurred or existed before the close of the Initial Offering and subsequent acquisitions from Andeavor. Neither the Partnership nor Andeavor are 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. On November 28, 2016, the EPA published the final Hazardous Waste Generator Improvements Rule. This rule provided some additional flexibility for small generators but also increased certain recordkeeping and administrative burdens. Several states are now in the process of adopting the new rule. Any additional changes in the regulations could increase our capital or operating costs.

We acquired two salt water disposal wells located in North Dakota on January 1, 2017. These facilities 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.

 
 
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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 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 Andeavor 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 Andeavor’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.

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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 effective March 2016. 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.

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 Andeavor’s refining operations are subject to many risks and operational hazards, which may result in business interruptions and shutdowns of our or Andeavor’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 Andeavor’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, Andeavor’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 insure 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.


 
 
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Risk Factors

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 Andeavor 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. The acquisition component of our growth strategy is based, in large part, on our expectation of ongoing divestitures of gathering, processing, transportation, storage and wholesale assets by industry participants, including Andeavor. If we are unable to make acquisitions from Andeavor or third parties because (1) there is a material decrease in divestitures of gathering, processing, transportation, storage and wholesale assets, (2) we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts,
(3) we are unable to obtain financing for these acquisitions on economically acceptable terms, (4) we are unsuccessful in our bid against competing potential purchasers, or (5) for any other reason, 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 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.

Our right of first offer to acquire certain of Andeavor’s existing assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets. In addition, we may not be able to acquire other assets that Andeavor has said it may offer to us in the future for acquisition.

Our Amended Omnibus Agreement provides us with a right of first offer on certain of Andeavor’s existing logistics assets for certain specified periods. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, Andeavor’s willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets and our ability to obtain financing on acceptable terms. We may not be able to successfully consummate any future acquisitions pursuant to our right of first offer, and Andeavor is under no obligation to accept any offer that we may choose to make. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any assets are offered for sale, and our decision will not be subject to unitholder approval. In addition, Andeavor may terminate our right of first offer if it no longer controls our general partner.

In addition to the assets with respect to which we have a right of first offer, Andeavor has sold to us additional logistics assets that it developed or acquired from third parties. However, we cannot provide assurance of Andeavor’s continued willingness to offer these types of assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to the assets or our ability to obtain financing on acceptable terms.

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 Andeavor’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 Andeavor 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 in the midwestern United States area could materially reduce the volume of crude oil gathered and transported by our High Plains System or the volume of natural gas gathered, processed, transported and fractionated by our Rockies, Southwest and Bakken Region assets.

The volume of crude oil that we gather and transport on our High Plains 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. Similarly, the volume of natural gas that we gather, process, and transport, and the volume of NGLs that we fractionate

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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 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. For example, in September 2013, we responded to a crude oil pipeline release of approximately 20,000 barrels in a rural field northeast of Tioga, North Dakota. Other spills, discharges and inadvertent releases may have previously occurred or could occur in the future; these releases could occur or may already have occurred at Andeavor’s refineries, 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 with Andeavor is generally limited to liabilities identified prior to the earlier of the date that Andeavor 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

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

Transportation and storage of crude oil and refined products over or under water or proximate to navigable or environmentally sensitive bodies of water occurs at many of our facilities. Such activity involves inherent risks and subjects us to the provisions of OPA 90 or similar state environmental laws that impose significant oil spill prevention and response obligations and can impose material cleanup liabilities without regard to fault for oil pollution in U.S. waters. To address the requirements of these laws, we have contracts with Andeavor, who contracts with third parties to provide coverage in the areas in which we transport or store crude oil and refined products; however, these companies may not be able to adequately contain a worst case discharge, being a spill of up to 125,000 barrels of crude oil from an above ground storage tank adjacent to water, and we cannot ensure that all of their services would be available for our or Andeavor’s use at any given time. There are many factors that could inhibit the availability of these service providers, including weather conditions, governmental regulations and other global events that they may be required to respond to by state or federal ruling. 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.

On October 3, 2016, PHMSA issued an Interim Final Rule (IFR) establishing procedures for the authority to issue emergency orders to pipeline operators. This authority can be used by PHMSA to address an unsafe conditions or practices that pose an imminent hazard to the public health and safety. Since this authority has never been utilized, it is unknown how the agency will use this newly granted power. There are also significant pipeline safety rulemakings under consideration by PHMSA include the Hazardous Liquid

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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. 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.

Andeavor is in the process of completing an enterprise resource planning project which aims to simplify business processes by implementing a standardized and scalable technology platform. Large information systems and business process transformations such as this one are complex and require significant investments in system software, business process development and employee resources. Our business and results of operations may be adversely affected if Andeavor experiences operating problems, scheduling delays, cost overages or service limitations.

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. For example, 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.

 
 
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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 Pipeline tariffs were successful, Andeavor’s minimum volume commitment under our High Plains Pipeline intrastate Transportation Services Agreement could be invalidated, and the intrastate volumes shipped on our High Plains Pipeline 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 Andeavor’s agreement to purchase, certain crude oil volume losses could be viewed as a preference to Andeavor and could result in negation of that provision and possible penalties.

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.


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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 Andeavor 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 Andeavor 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 Andeavor 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 Andeavor’s obligations under those agreements range from five to ten years. If Andeavor 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 Andeavor 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, Andeavor, accounted for 44% of our total revenues in the year ended December 31, 2017. We expect to derive a significant amount of our revenues from Andeavor 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 Andeavor), 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;
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-Andeavor 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 Andeavor, our desire to provide services pursuant to fee-based contracts and Andeavor’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.


 
 
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Some of the gathering and processing agreements of the Rockies Natural Gas Business 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 to the Rockies Natural Gas Business, while also minimizing direct commodity price risk. Under these minimum volume commitments, the customers of the Rockies Natural Gas Business 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 the gathering and processing agreements of the Rockies Natural Gas Business 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, Bureau of Land Management, 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.

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 Facility, exposes us to short-term changes in market rates that impact our interest expense. Fixed rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates, or that we may be obligated to rates higher than the current market.

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.

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

As of December 31, 2017, we had $4.2 billion aggregate principal amount of debt outstanding, and we may incur significant additional debt obligations in the future. For example, in November 2017, we issued an additional $1.75 billion aggregate principal amount of senior notes, the proceeds of which were used to, among other things, redeem all of our outstanding 5.875% Senior Notes due 2020 and 6.125% Senior Notes due 2021 and repay borrowings under our Dropdown Credit Facility. 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.

Andeavor’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.

Andeavor 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 Andeavor were to default under certain of its debt obligations, there is a risk that Andeavor’s creditors would attempt to assert claims against our assets during the litigation of their claims against Andeavor. 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, Andeavor’s debt ratings when assigning ours because of Andeavor’s ownership interest in us, the significant commercial relationships between Andeavor and us, and our reliance on Andeavor for a substantial portion of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Andeavor, 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.

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;

 
 
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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 Andeavor with respect to those expenses and payment of an annual corporate services fee to Andeavor;
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 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;
make certain investments;
dispose of assets in excess of certain amounts;
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 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.

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

Any work stoppage by Andeavor employees who provide services to us pursuant to the First Amended and Restated Secondment and Logistics Services Agreement (the “Secondment Agreement”) or the Amended Omnibus Agreement may have a negative impact on our business. Additionally, Andeavor is a significant customer and any strike action or work stoppage at any of Andeavor’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.

Andeavor may suspend, reduce or terminate its obligations under our commercial agreements and our Secondment Agreement 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 Secondment Agreement with Andeavor include provisions that permit Andeavor 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 Andeavor may decide to permanently or indefinitely suspend refining operations at one or more of its refineries. Andeavor 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, Andeavor’s and our obligations under these agreements will be proportionately reduced or suspended to the extent that we are unable to perform. As defined in our commercial agreements and in the Secondment Agreement, force majeure events include any 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.

Any of these events could result in our no longer being required to transport or distribute Andeavor’s minimum throughput commitments on our pipelines or terminals, respectively, and in Andeavor 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 Andeavor’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.


 
 
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Risks Relating to Our Partnership Structure

Andeavor 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, including Andeavor, may have conflicts of interest with us and they may favor their own interests to the detriment of us and our common unitholders.

As of February 15, 2018, Andeavor and its affiliates own an approximate 59% 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, Andeavor. Conflicts of interest may arise between Andeavor 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 Andeavor, over the interests of our common unitholders. These conflicts include the following situations:

Neither our partnership agreement nor any other agreement requires Andeavor to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by Andeavor 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. Andeavor’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Andeavor;
Andeavor, 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;
Andeavor 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 permits our general partner to classify up to $30 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus;
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 Andeavor; 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. Other than as provided in our Amended Omnibus Agreement with Andeavor, 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 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 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.


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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 also requires our general partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. In addition, 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 Secondment Agreement, our general partner determines the amount of these expenses. Under the terms of the Amended Omnibus Agreement, we are required to pay Andeavor an annual corporate services fee, currently $13 million, for the provision of various centralized corporate services. Under the terms of our Secondment Agreement, we pay Andeavor a net annual service fee, currently $29 million, for services performed by field-level employees at the majority of the facilities acquired from Andeavor. We reimburse Andeavor for any direct costs actually incurred by Andeavor 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. Andeavor is currently the sole member 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 59% of our outstanding common units and, as a result, our public unitholders cannot remove our general partners 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 Andeavor to transfer its membership interest in our general partner to a third party. The new partners 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 of directors 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 6.875% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “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 Revolving Credit Facility 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

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amounts payable upon a liquidation event or additional indebtedness could affect our ability to pay distributions on, redeem or 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.
Andeavor 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 15, 2018, Andeavor holds 127,889,386 common units. Additionally, we have agreed to provide Andeavor with 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 or on any trading market that may develop.

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

Andeavor and its affiliates are not restricted from competing with us, except under certain circumstances. Under our Amended Omnibus Agreement, Andeavor and its affiliates generally may not own or operate crude oil or refined products pipelines, terminals or storage facilities in the U.S. that are not within, directly connected to, substantially dedicated to, or otherwise an integral part of, any refinery owned, acquired or constructed by Andeavor. This restriction, however, does not apply to:

any assets that were owned by Andeavor at the closing of our initial public offering (including replacements or expansions of those assets);
any assets acquired or constructed by Andeavor to replace one of our assets that no longer provides services to Andeavor due to the occurrence of a force majeure event under one of our commercial agreements with Andeavor that prevents us from providing services under such agreement;
any asset or business that Andeavor acquires or constructs that has a fair market value of less than $5 million; and
any asset or business that Andeavor acquires or constructs that has a fair market value of $5 million or more if we have been offered the opportunity to purchase the asset or business for fair market value not later than six months after completion of such acquisition or construction, and we decline to do so.

As a result, Andeavor has the ability to construct assets, which directly compete with our assets so long as they are integral to a refinery owned by Andeavor. The limitations on the ability of Andeavor to compete with us are terminable by either party if Andeavor ceases to control our general partner.

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.

 
 
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Risk Factors


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.

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 of directors 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

Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition and cash flow.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that makes significant changes to U.S. federal income tax laws. Among other changes, the Tax Act (i) introduces a new deduction on certain pass-through income, (ii) repeals the partnership technical termination rule and (iii) imposes a new limitation on the deductibility of interest expense. The Tax Act is complex and far-reaching and we have not completed our analysis of the impact its enactment has on us. There may be other material adverse effects resulting from the Tax Act that we have not identified and that could have an adverse effect on our business, results of operations, financial condition and cash flow.

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Risk Factors


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 or any other tax matter affecting us.

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.

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, 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 us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us and change the character or treatment of portions of our income. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships, including the elimination of partnership tax treatment for publicly traded partnerships. For example, on May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations regarding qualifying income under Section 7704(d)(1)(E) of the Internal Revenue Code. On January 24, 2017, final regulations were published. We believe the income that we treat as qualifying income satisfies the requirements for qualifying income under both the proposed regulations and the final regulations. However, we are unable to predict whether any future changes to the U.S. federal income tax laws will be enacted that could adversely affect us.

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

 
 
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Risk Factors

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 individual retirement accounts (“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.

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.


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Risk Factors

We will adopt 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 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. Pursuant to this new legislation, we will designate a person (our general partner) to act as the “partnership representative” who shall have the sole authority to act on our behalf with respect to dealings with the IRS under these new audit procedures.

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.

 
 
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Properties, Legal Proceedings and Mine Safety Disclosures

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 and refined products. 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

Unit Price and Cash Distributions

Our common units trade on the New York Stock Exchange under the symbol “ANDX”. As of February 15, 2018, Andeavor owned 127,889,386 of our common units which constitutes a 59% ownership interest in us, and 80,000 Andeavor Logistics TexNew Mex Units (the “TexNew Mex Units”). The public held 89,275,038 of our outstanding common units including common units held on behalf of others as of February 15, 2018. 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 five holders of record of our common units as of February 15, 2018.

Daily High and Low Intraday Trading Prices per Common Unit and Cash Distributions

 
2017
 
2016
 
Sales Prices per
 
Quarterly Cash Distribution per Unit (a)
 
Sales Prices per
 
Quarterly Cash Distribution per Unit (a)
 
Common Unit
 
 
Common Unit
 
Quarter Ended
High
 
Low
 
 
High
 
Low
 
December 31
$
50.04

 
$
42.18

 
$
1.0000

 
$
51.87

 
$
43.00

 
$
0.9100

September 30
54.74

 
45.72

 
0.9852

 
50.70

 
44.55

 
0.8750

June 30 (b)
55.79

 
46.13

 
0.9710

 
51.35

 
41.22

 
0.8420

March 31
60.14

 
50.96

 
0.9400

 
51.43

 
35.18

 
0.8100


(a)
Represents cash distributions attributable to the quarter and declared and paid within 45 days of quarter end in accordance with our partnership agreement.
(b)
On July 25, 2017, WNRL declared a quarterly cash distribution of $0.4675 per unit, which was paid on August 18, 2017.

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 “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 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 (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, with the first such payment made on February 15, 2018. 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 pro-rated initial distribution on the Preferred Units was paid on February 15, 2018 in an amount equal to approximately $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

 
 
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Market for Equity, Stockholder Matters and Purchases of Equity Securities
 


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.

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

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, 2017, 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 Andeavor, and those assets, liabilities and results of operations.

In 2017, 2016 and 2015, we entered into various transactions with Andeavor and our general partner, TLGP, pursuant to which Andeavor Logistics acquired from Andeavor the following:

crude oil, feedstock and refined products storage, the Anacortes marine terminal, a manifest rail facility and crude oil and refined products pipelines located in Anacortes, Washington on November 8, 2017;
logistic assets owned by WNRL, which consisted of pipelines, gathering, terminalling, storage, transportation and wholesale fuel distribution assets, and provides services to Andeavor’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;
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; and
a crude oil and refined products storage tank facility located at Andeavor’s Los Angeles refinery and a 50% fee interest in a pipeline that transports jet fuel from Andeavor’s Los Angeles refinery to the Los Angeles International Airport, effective November 12, 2015.

These transactions are collectively referred to as “Acquisitions from Andeavor”. These transactions were transfers between entities under common control. Accordingly, the financial information contained herein of the Andeavor Logistics Predecessors and Andeavor Logistics have been retrospectively adjusted to include the historical results of the Predecessors. While the Anacortes Logistics Assets acquisition is a common control transaction, prior periods have not been recast as these assets do not constitute a business in accordance with the Accounting Standard Update, “Clarifying the Definition of a Business”. Other than WNRL, our Predecessors did not record revenue for intercompany trucking, terminalling, storage and short-haul pipeline transportation services.

All financial results have also been adjusted for subsequent transactions with Predecessors to the period that the assets were initially acquired by Andeavor. For additional information regarding these adjustments, see “Business Strategy and Overview” and “Results of Operations” in Item 7.


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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,
 
2017 (a)
 
2016 (a)
 
2015 (a)
 
2014 (a)
 
2013 (a)
 
(In millions, except units and per unit amounts)
Statement of Operations Data
 
 
 
 
 
 
 
 
 
Total revenues (b)
$
3,213

 
$
1,220

 
$
1,112

 
$
600

 
$
313

Net earnings
373

 
315

 
249

 
56

 
18

(Earnings) loss attributable to Predecessors
(24
)
 
24

 
43

 
46

 
62

Net earnings attributable to noncontrolling interest

 

 
(20
)
 
(3
)
 

Net earnings attributable to partners
349

 
339

 
272

 
99

 
80

General partner’s interest in net earnings, including incentive distribution rights
79

 
152

 
73

 
43

 
12

Common unitholders’ interest in net earnings
267

 
187

 
199

 
43

 
46

Subordinated unitholders’ interest in net earnings

 

 

 
13

 
22

Net earnings per limited partner unit:
 
 
 
 
 
 
 
 
 
Common - basic
$
2.11

 
$
1.87

 
$
2.33

 
$
0.96

 
$
1.48

Common - diluted
2.11

 
1.87

 
2.33

 
0.96

 
1.47

Subordinated - basic and diluted

 

 

 
0.62

 
1.35

Cash distribution per unit
3.8062

 
3.3070

 
2.8350

 
2.4125

 
2.0175

 
 
 
 
 
 
 
 
 
 
 
As of December 31,
 
2017
 
2016
 
2015 (a)
 
2014 (a)
 
2013 (a)
 
(in millions)
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total assets
$
8,169

 
$
5,860

 
$
5,131

 
$
4,955

 
$
1,560

Total debt, net of unamortized issuance costs
4,128

 
4,054

 
2,844

 
2,544

 
1,141


(a)
Includes the historical results related to Andeavor Logistics and Predecessors for years 2017, 2016, 2015 and 2014. For the year ended 2013, recasted amounts are not shown because management does not believe presentation of these impacts is material to an investor’s understanding of Andeavor Logistics’ current operations.
(b)
Other than WNRL and transportation regulated by the FERC and the Regulatory Commission of Alaska tariffs charged to Andeavor on the refined products pipeline included in the logistics assets acquired in 2014, our Predecessors did not record revenue for transactions with Andeavor for assets acquired in the Acquisitions from Andeavor prior to the effective date of each acquisition.


 
 
December 31, 2017 | 37

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 LP,” “Andeavor Logistics,” “the Partnership,” “we,” “us” or “our” refer to Andeavor Logistics LP, one or more of its consolidated subsidiaries or all of them taken as a whole. Unless the context otherwise requires, references in this report to “Andeavor” refer collectively to Andeavor and any of its subsidiaries, other than Andeavor Logistics, its subsidiaries and its general partner.

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 implemented organic and strategic investments to transform the composition of our portfolio. Refer to Part I, 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.

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 Andeavor 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 Andeavor Strategic Expansion




 
●    Strategically partnering with Andeavor on acquisitions in refining and marketing value chains

●    Capturing full value of Andeavor’s embedded logistics assets
 
 

Relative to these goals, in 2018, we intend to continue implementing this strategy and have completed or announced plans to expand our Terminalling and Transportation business across the western U.S. through:

increasing our terminalling volumes by expanding capacity and growing our third-party services at certain of our terminals;
optimizing Andeavor volumes and growing third-party throughput at our Terminalling and Transportation assets; and
pursuing strategic assets in the western U.S.

In addition, we have completed or announced plans to grow our assets on our Gathering and Processing segment in support of third-party demand for crude oil, natural gas and water gathering services, natural gas processing services, as well as serving

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Management’s Discussion and Analysis

Andeavor’s demand for Bakken crude oil in the mid-continent and west coast refining systems and providing crude oil supply to support Andeavor’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, principally in the Delaware basin where Andeavor has a strong logistics asset base, crude oil marketing capabilities and meaningful refining offtake; and
pursuing strategic assets across the western U.S. including potential acquisitions from Andeavor.

During 2017, we had the following specific accomplishments as they relate to our strategy and goals, which are discussed further in this Management’s Discussion and Analysis:

completed the merger of WNRL in a unit exchange further enhancing our existing segments and adding a wholesale business;
acquired crude oil, natural gas and produced water gathering systems and two natural gas processing facilities in North Dakota;
acquired logistics assets from Andeavor including storage, marine terminal, rail facility and pipelines near Andeavor’s Anacortes refinery;
concurrent with the WNRL Merger, completed the IDR/GP Transaction through issuing common units to Andeavor in exchange for the IDR and the economic interest of the general partner units;
achieved investment grade with Fitch Ratings assigning us a first-time Long-Term Issuer Default Rating of “BBB-” and S&P Global Ratings raising our corporate credit and senior unsecured issue ratings to "BBB-" with a stable outlook;
issued our inaugural investment grade offering with $1.75 billion of aggregate principal senior notes using the proceeds to refinance our higher interest rate senior notes; and
completed a Preferred Units offering using the proceeds to repay senior notes and Revolving Credit Facility borrowings.

Acquisitions

Wamsutter Pipeline System
On February 15, 2018, we announced an agreement to acquire the Wamsutter pipeline system from Plains All American, L.P. consisting of 575 miles of crude oil transportation pipelines that connect into Salt Lake City refineries. The acquisition, which is subject to customary closing conditions including regulatory approval, is anticipated to close in the first half of 2018. The acquisition is expected to be financed with borrowings from the Revolving Credit Facility.

Anacortes Logistics Assets
On November 8, 2017, we completed the Anacortes Logistics Assets acquisition from a subsidiary of Andeavor for total consideration of $445 million. The Anacortes Logistics Assets include 3.9 million barrels of crude oil, feedstock and refined products storage at Andeavor’s Anacortes refinery, the Anacortes marine terminal with 73 Mbpd of feedstock and refined product throughput, a manifest rail facility with 4 thousand barrels of throughput and crude oil and refined products pipelines with 111 Mbpd of throughput combined. We paid $445 million, including $400 million of cash financed with borrowings on our Dropdown Credit Facility and $45 million in common units issued to Andeavor.

WNRL Merger and IDR Buy-In
Effective October 30, 2017, Andeavor Logistics closed the WNRL Merger exchanging all outstanding common units of WNRL with units of Andeavor Logistics. WNRL public unitholders received 0.5233 units of Andeavor Logistics for each WNRL unit held while Andeavor effectively received 0.4639 units as certain units held by Andeavor’s subsidiaries were canceled in the transaction. The combined effective exchange ratio for the WNRL Merger was 0.4921 units of Andeavor Logistics for every unit of WNRL. Concurrently with the closing of the WNRL Merger, a direct, wholly-owned subsidiary of Andeavor Logistics merged with and into Western Refining Logistics GP, LLC (“WNRL General Partner”) with WNRL General Partner being the surviving entity and becoming a wholly-owned subsidiary of Andeavor Logistics.

The closing of the WNRL Merger was conditioned upon, among other things, the adoption and effectiveness of the Second Amended and Restated Agreement of Limited Partnership of Andeavor Logistics LP, pursuant to which, simultaneously with the closing of the WNRL Merger: the IDR Exchange and the IDR/GP Transaction took place, and Andeavor and its affiliates, including TLGP, agreed to increase and extend existing waivers on distributions to Andeavor and its affiliates by $60 million to an aggregate of $160 million between 2017 and 2019. As consideration for the IDR/GP Transaction, TLGP was issued 78.0 million common units in Andeavor Logistics simultaneously with the closing of the WNRL Merger.


 
 
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Management’s Discussion and Analysis

North Dakota Gathering and Processing Assets
On January 1, 2017, we acquired the North Dakota Gathering and Processing Assets for total consideration of approximately $705 million funded with cash on-hand, which included borrowings under the Revolving Credit Facility. The North Dakota Gathering and Processing Assets include over 650 miles of crude oil, natural gas, and produced water gathering pipelines, 170 MMcf per day of natural gas processing capacity and 18.7 Mbpd of fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. The revenue from the assets is approximately 90% fee-based and backed by acreage dedications from ten producers.

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.

Current Market Developments

Although we have minimal exposure to commodity prices, the spot prices of the commodities that we handle largely improved in 2017. Crude oil, refined products, and the majority of NGL prices increased while prices for natural gas decreased. The U.S. oil and gas drilling landscape improved markedly from 2016 due to price appreciation, increased rig counts and operator efficiencies. Domestic crude production exhibited material growth in 2017, which resulted in significantly higher U.S. crude exports. The higher crude price environment seen in the fourth quarter has further improved shale economics and U.S. crude production is expected to continue to grow in 2018. From a products perspective, growing export opportunities are providing an incentive for U.S. refiners to maximize production of gasoline and diesel. These factors create a positive outlook for U.S. oil, natural gas and refined product throughput volumes, however, regional impacts may differ. Within our Gathering and Processing segment, gas gathering and throughput volumes remain below levels experienced in 2015, our first full year of operations of the Rockies Natural Gas Business. Volumes declined significantly in 2016 due to decreased rig counts following revisions to natural gas producers’ drilling and production plans given the lower price environment at the time. However, we continue to experience improvements in the segment based on the 2017 commodity pricing environment, the acquisition of the North Dakota Gathering and Processing Assets, organic growth projects coming on-line, and expanded drilling plans in the Pinedale area.

Continued improvements in the U.S. economic landscape such as lower unemployment, wage growth, strong consumer sentiment, robust manufacturing and expansion of petrochemical plants support healthy refined product demand from our downstream and marketing customers. We continue to monitor the impact of commodity prices and fundamentals on our business. Given the outlined market conditions, we believe our diversified portfolio of businesses as well as our strong customer base are sufficient to continue to meet our goals and objectives outlined above.

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;
Average crude oil and water gathering revenue per barrel; 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 and average margin per gallon; other companies may calculate these in different ways.


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Management’s Discussion and Analysis

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 Andeavor 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 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 Andeavor or third-party volumes.

Additionally, increased throughput may depend on Andeavor 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.

Our operating expenses are also affected by the imbalance gain and loss provisions in our active published tariffs and in our commercial agreements with Andeavor. 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 specified 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 less than amounts specified reduce our operating expenses in the period in which they are realized to the extent they are within the loss allowance and increase our operating expenses in such period to the extent they exceed the loss allowance. 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 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.

There are differences in the way our Predecessors recorded revenues and the way the Partnership records revenues after the Acquisitions from Andeavor, as defined in Note 1 to our consolidated financial statements in Item 8. The assets that we acquire from Andeavor have historically been a part of the integrated operations of Andeavor, and, other than WNRL, our Predecessors generally recognized only the costs and did not record revenue for transactions with Andeavor. Accordingly, the revenues in our Predecessors’ historical combined financial statements relate only to amounts received from third parties for these services.

On June 1, 2017, pursuant to the Agreement and Plan of Merger, dated as of November 16, 2016, by and among Western Refining, Inc. (“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, 2017.


 
 
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Management’s Discussion and Analysis

We changed our operating segment presentation in the first quarter of 2017 to reflect our expanded gathering and processing operations and capabilities. With the completion of the North Dakota Gathering and Processing Assets acquisition on January 1, 2017, our gathering and processing assets and operations expanded significantly and enhanced our ability to offer integrated gathering and processing services to our customers. Comparable prior period information for the newly presented Gathering and Processing segment has been recast to reflect our current presentation. No changes were deemed necessary to our Terminalling and Transportation segment. As a result of the WNRL Merger, we have presented the wholesale fuel distribution business as a separate segment and included the asphalt trucking and crude trucking operations in the Terminalling and Transportation segment and Gathering and Processing Segment, respectively. Given the business’s focus on providing integrated services along with the revised reporting structure implemented by management to assess performance and make resource allocation decisions, we have determined our operating segments, which are the same for reporting purposes, are the Terminalling and Transportation segment, Gathering and Processing segment, and Wholesale segment.

We have a 78% interest in RGS, which owns and operates the infrastructure that transports gas from certain fields to several re-delivery points in southwestern Wyoming, including natural gas processing facilities that are owned by us or a third party. Prior to 2016, we consolidated RGS; however, upon the reassessment performed in conjunction with our adoption of ASU 2015-02, “Amendments to the Consolidation Analysis”, in 2016, we determined RGS represents a variable interest entity to us for which we are not the primary beneficiary resulting in the deconsolidation of RGS and the reporting of RGS as an equity method investment. RGS is reflected on a consolidated basis in our results of operations for the year ended December 31, 2015.

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. These non-GAAP measures are defined in our glossary of terms. These measures are important factors in assessing our operating results and profitability and include:

Financial non-GAAP measure of EBITDA;
Financial non-GAAP measure of Segment EBITDA;
Liquidity non-GAAP measure of distributable cash flow, which is 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;
Liquidity non-GAAP measure of distributable cash flow attributable to common unitholders, which is calculated as distributable cash flow minus distributions associated with the Preferred Units;
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.

Management also uses these measures to assess internal performance, and we believe they may provide meaningful supplemental information to the users of our financial statements. 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.

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 “Non-GAAP Reconciliations” section.


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Management’s Discussion and Analysis

Consolidated Results

Highlights (in millions)

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(a)
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

2017 Versus 2016

Operating Income Reconciliation by Segment (in millions)

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Overview
Our net earnings for 2017 increased $58 million, or 18%, to $373 million from $315 million for 2016 primarily driven by North Dakota Gathering and Processing Assets acquisition and increased contributions from the Acquisitions from Andeavor 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 $281 million reflecting the impact of the Acquisitions from Andeavor, 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. The revenue and related cost of fuels are reported gross on our financial statements. Both of these revenue streams are contributing to our higher revenue and operating costs.

Segment Results
Operating income increased $195 million to $682 million during 2017 compared to $487 million for 2016 driven by contributions from the Acquisitions from Andeavor 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 $2.0 billion, or 163%, 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 owned by Andeavor (“the Alaska Storage and Terminalling Assets”) and the Northern California Terminalling and Storage Assets acquired from Andeavor 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 from 2016 due to the WNRL Merger and North Dakota Gathering and Processing Assets, respectively.

Operating Expenses
Operating expenses increased $184 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 was due to the sale of a products terminal in Alaska.

Interest and Financing Costs, Net
Net interest and financing costs increased $131 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 as discussed in the “Capital Resources and Liquidity” section.



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Management’s Discussion and Analysis


2016 Versus 2015

Operating Income Reconciliation by Segment (in millions)

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Overview
Our net earnings for 2016 increased $66 million, or 27%, to $315 million from $249 million for 2015 primarily driven by an increase in revenues partially offset by an increase to interest and financing costs. EBITDA increased $109 million corresponding with the $108 million increase to revenues as increase to operating expenses were offset by decreases in our general and administrative expenses.

Segment Results
Operating income increased $94 million to $487 million during 2016 compared to $393 million for 2015 driven by increases in our Terminalling and Transportation segment that had contributions from the Acquisitions from Andeavor. Refer to our detailed discussion of each segment’s operating and financial results contained in this section.

Revenues
Revenues for 2016 increased by $108 million, or 10%, to $1.2 billion benefiting from a full year of operations of the crude oil and refined product storage and pipeline assets in Los Angeles, California (the "LA Storage and Handling Assets") that were purchased from Andeavor in November 2015 and the acquisition of the Alaska Storage and Terminalling Assets in 2016 that were purchased from Andeavor in July and September 2016. Terminalling and Transportation segment revenues increased $110 million as a result of the commercial storage agreements executed with Andeavor in connection with the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets. Revenues in our Gathering and Processing segments remained flat compared to 2015.

Operating Expenses
Operating expenses increased $14 million primarily due to the impact of deconsolidation of RGS in 2016 where transactions are reported gross. The related transactions with RGS in 2015 were eliminated during consolidation. Partially offsetting the increase was a decline in expenses recognized in connection with our environmental accruals.

Interest and Financing Costs, Net
Net interest and financing costs increased $41 million primarily related to the issuance of new senior notes during 2016 and the write-off of unamortized debt issuance costs in connection with debt transactions as discussed in the “Capital Resources and Liquidity” section.



 
 
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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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Volumes
Terminalling throughput increased 444 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 Andeavor, 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 volume increased 34 Mbpd, or 4%, in 2017 compared to 2016, which was primarily attributable an increase in pipeline volumes in Southern California from strong refinery utilization.

Terminalling throughput increased 29 Mbpd in 2016 compared to 2015 primarily as a result of stronger customer demand, terminalling assets from the Alaska Storage and Terminalling Assets acquisition and organic growth projects adding new capabilities to our system. Pipeline transportation throughput increased 43 Mbpd in 2016 compared to 2015 primarily due to increased utilization of the southern California transportation pipeline system and performance enhancements.


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Management’s Discussion and Analysis

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

 
Year Ended December 31,
 
2017 (a)
 
2016 (a)
 
2015 (a)
Revenues
 
 
 
 
 
Terminalling
$
688

 
$
480

 
$
377

Pipeline transportation
130

 
125

 
118

Other revenues
18

 

 

Total Revenues
836

 
605

 
495

Costs and Expenses
 
 
 
 
 
Operating expenses (b)
257

 
193

 
184

Depreciation and amortization expenses
102

 
83

 
76

General and administrative expenses
38

 
32

 
32

(Gain) loss on asset disposals and impairments
(25
)
 
1

 

Operating Income
$
464

 
$
296

 
$
203

Rates (c)
 
 
 
 
 
Average terminalling revenue per barrel
$
1.32

 
$
1.33

 
$
1.08

Average pipeline transportation revenue per barrel
$
0.40

 
$
0.39

 
$
0.39


(a)
Adjusted to include the historical results of the Predecessors. Other than WNRL, our Predecessors did not record revenue for transactions with Andeavor in the Terminalling and Transportation segment prior to the effective date of each acquisition.
(b)
Operating expenses include net imbalance settlement gains of $5 million, $3 million and $4 million in the years ended December 31, 2017, 2016 and 2015, respectively.
(c)
Amounts may not recalculate due to rounding of dollar and volume information.

 
2017 Versus 2016

Our Terminalling and Transportation segment’s operating income increased $168 million, or 57% in 2017 compared to 2016. Segment EBITDA increased $190 million, or 50% in 2017 compared to 2016.

Revenues increased $231 million, or 38%, to $836 million in 2017 compared to $605 million in 2016 primarily attributable to revenues associated with new commercial terminalling and storage agreements executed with Andeavor in connection 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 $64 million, or 33%, to $257 million in 2017 compared to $193 million in 2016 due to the recent acquisitions.

Depreciation and amortization expenses increased $19 million, or 23%, to $102 million in 2017 compared to $83 million in 2016 due to the recent acquisitions.

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

2016 Versus 2015

Our Terminalling and Transportation segment’s operating income increased $93 million, or 46% in 2016 compared to 2015. Segment EBITDA increased $100 million, or 36% in 2016 compared to 2015.

Revenues increased $110 million, or 22%, to $605 million in 2016 compared to $495 million in 2015 primarily as a result of the commercial storage agreements executed with Andeavor in connection with the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets, as well as increased throughput volumes.

Operating expenses increased $9 million, or 5%, to $193 million in 2016 compared to $184 million in 2015 primarily as a result of the higher throughput volumes.

Depreciation and amortization expenses increased $7 million, or 9%, to $83 million in 2016 compared to $76 million in 2015 primarily as a result of the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets.


 
 
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Management’s Discussion and Analysis

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12074155&doc=19 http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12074155&doc=20 Gathering and Processing

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.

Volumes
NGL sales volume increased 800 bpd, 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, or 10%, in 2017, driven primarily by the North Dakota Gathering and Processing Assets acquired providing more volumes on our systems. Crude oil and water gathering volumes increased 84 Mbpd, or 40%, during 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 Andeavor’s Mandan refinery, which impacted volumes as well as the average crude oil and water revenue per barrel due to shorter pipeline haul movements.

Gas gathering and processing throughput volumes decreased 198 thousand MMBtu/d in 2016 compared to 2015, primarily due to the exclusion of volumes associated with RGS following its deconsolidation in 2016 and lower natural gas production being delivered to our processing systems. Crude oil and water gathering volumes increased 24 Mbpd, or 13%, in 2016, as a result of projects to expand the pipeline gathering system capabilities, which include additional origin and destination interconnections.


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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,
 
2017 (a)
 
2016
 
2015
Revenues
 
 
 
 
 
NGL sales (b)
$
369

 
$
103

 
$
99

Gas gathering and processing
333

 
264

 
274

Crude oil and water gathering
228

 
133

 
123

Pass-thru and other (c)
165

 
115

 
121

Total Revenues
1,095

 
615

 
617

Costs and Expenses
 
 
 
 
 
NGL expense (excluding items shown separately below) (b)(c)
265

 
2

 

Operating expenses (d)
354

 
249

 
244

Depreciation and amortization expenses
175

 
107

 
111

General and administrative expenses
44

 
36

 
44

Loss on asset disposals and impairments

 
3

 
1

Operating Income
$
257

 
$
218

 
$
217

Rates (e)
 
 
 
 
 
Average margin on NGL sales per barrel (b)(c)(f)
$
34.77

 
$
36.59

 
$
34.38

Average gas gathering and processing revenue per MMBtu
$
0.95

 
$
0.82

 
$
0.69

Average crude oil and water gathering revenue per barrel
$
2.11

 
$
1.72

 
$
1.79


(a)
Adjusted to include the historical results of the Predecessors.
(b)
In 2017, we had 22.2 Mbpd of gross NGL sales under POP and keep-whole arrangements. We retained 8.3 Mbpd 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 approximately $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)
Operating expenses include net imbalance settlement gains of $8 million, $3 million and $2 million in the years ended December 31, 2017, 2016 and 2015, respectively.
(e)
Amounts may not recalculate due to rounding of dollar and volume information.
(f)
See “Non-GAAP Reconciliations” section below for further information regarding this non-GAAP measure.
 

2017 Versus 2016

Our Gathering and Processing segment’s operating income increased $39 million, or 18% in 2017 compared to 2016. Segment EBITDA increased $98 million, or 28% 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 and expanded capabilities on existing assets along with the addition of the 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.

2016 Versus 2015

Our Gathering and Processing segment’s operating income remained relatively flat in 2016 compared to 2015. Segment EBITDA increased $9 million, or 3% in 2016 compared to 2015.

Gathering and processing revenues remained relatively flat in 2016 compared to 2015 and operating expenses increased $5 million, or 2%, to $249 million in 2016 compared to $244 million in 2015, primarily related to the reporting of gross operating expense related to our transactions with RGS for 2016 that were previously eliminated in 2015, partially offset by lower environmental remediation costs. Depreciation and amortization expense decreased $4 million, or 4%, to $107 million in 2016 compared to $111 million in 2015 primarily due to the deconsolidation of RGS in 2016.



 
 
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Management’s Discussion and Analysis

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12074155&doc=18 Wholesale

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

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

 
Period Ended
 
December 31, 2017 (a)
Revenues
 
Fuel sales
$
1,267

Other wholesale
15

Total Revenues
1,282

Costs and Expenses
 
Cost of fuel and other (excluding items shown separately below)
1,244

Operating expenses (excluding depreciation and amortization)
15

Depreciation and amortization expenses
5

General and administrative expenses
3

Operating Income
$
15

 
 
Rates (b)
 
Fuel sales volumes (millions of gallons)
722

Average wholesale fuel sales margin per gallon (c)

3.0
¢

(a)
Adjusted to include the historical results of the Predecessors. The 2017 period only includes the results beginning June 1, 2017.
(b)
Amounts may not recalculate due to rounding of dollar and volume information.
(c)
See “Non-GAAP Reconciliations” section below for further information regarding this non-GAAP measure.

 

Financial Results
The Wholesale segment’s operating income and Segment EBITDA was $15 million and $20 million, respectively, for the period ended December 31, 2017. This represented 2% of both our combined segment operating income and Segment EBITDA. Our wholesale business operates under commercial and service agreements with Andeavor and sells refined products to third parties. Revenues, earnings and cash flows from our Wholesale segment are primarily affected by the sales volumes and margins of gasoline and diesel fuel.



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Management’s Discussion and Analysis

Non-GAAP Reconciliations

Reconciliation of Net Earnings to EBITDA (in millions)

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

 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2017
 
2016
 
2015
 
2017
 
Terminalling and Transportation
Gathering and Processing
Wholesale
Segment Operating Income
$
464

 
$
296

 
$
203

 
$
257

 
$
218

 
$
217

 
$
15

Depreciation and amortization expenses
102

 
83

 
76

 
175

 
107

 
111

 
5

Equity in earnings of equity method investments

 

 

 
10

 
13

 
7

 

Other income, net
3

 

 

 

 
6

 

 

Segment EBITDA
$
569

 
$
379

 
$
279

 
$
442

 
$
344

 
$
335

 
$
20



 
 
December 31, 2017 | 51

Management’s Discussion and Analysis

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

 
Year Ended December 31,
 
2017 (a)
 
2016 (a)
 
2015 (a)
Net Cash from Operating Activities
$
709

 
$
498

 
$
436

Changes in assets and liabilities
29

 
44

 
19

Predecessors impact
(48
)
 
17

 
34

Maintenance capital expenditures (b)
(99
)
 
(72
)
 
(54
)
Reimbursement for maintenance capital expenditures (b)
31

 
28

 
9

Net earnings attributable to noncontrolling interest (c)

 

 
(18
)
Other adjustments for noncontrolling interest (d)

 

 
(21
)
Adjustments for equity method investments (e)
2

 
2

 
(3
)
Gain (loss) on sales of assets, net of proceeds
29

 
8

 
(1
)
Other (f)
15

 
7

 
21

Distributable Cash Flow
668

 
532

 
422

Less: Preferred unit distributions (g)
(3
)
 

 

Distributable Cash Flow Attributable to Common Unitholders
$
665

 
$
532

 
$
422


(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)
Excludes $2 million of undistributed QEP Midstream Partners, LP (“QEPM”) earnings prior to the closing of the merger of QEPM with Andeavor Logistics for the year ended December 31, 2015, that unitholders of QEPM were entitled to receive, but unitholders of Andeavor Logistics received as a result of the merger.
(d)
Adjustments represent cash distributions in excess of (or less than) our controlling interest in income and depreciation as well as other adjustments for depreciation and maintenance capital expenditures applicable to the noncontrolling interest obtained in the Rockies Natural Gas Business Acquisition.
(e)
We adjust net cash from operating activities to reflect cash distributions received from equity method investments attributed to the period reported for the purposes of calculating distributable cash flow.
(f)
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 and the inclusion of $13 million for acquired deficiency revenue billings to customers for the year ended December 31, 2015.
(g)
Represents the cash distributions earned by the Preferred Units for the year ended December 31, 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.


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Management’s Discussion and Analysis

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

 
Year Ended December 31,
 
2017
 
2016
 
2015
Segment Operating Income
$
257

 
$
218

 
$
217

Add back:
 
 
 
 
 
Operating expenses
354

 
249

 
244

Depreciation and amortization expenses
175

 
107

 
111

General and administrative expenses
44

 
36

 
44

Loss on asset disposals and impairments

 
3

 
1

Other commodity purchases (a)
2

 

 

Subtract:
 
 
 
 
 
Gas gathering and processing revenues
(333
)
 
(264
)
 
(274
)
Crude oil gathering revenues
(228
)
 
(133
)
 
(123
)
Pass-thru and other revenues
(165
)
 
(115
)
 
(121
)
Margin on NGL Sales
$
106

 
$
101

 
$
99

Divided by Total Volumes for the Period:
 
 
 
 
 
NGLs sales volumes (Mbpd)
8.3

 
7.5

 
7.9

Number of days in the period
365

 
366

 
365

Total volumes for the period (thousands of barrels) (b)
3,030

 
2,745

 
2,884

Average Margin on NGL Sales per Barrel (b)
$
34.77

 
$
36.59

 
$
34.38


(a)
Included in the NGL expense for the year ended December 31, 2017 was approximately $2 million of costs related to crude oil volumes obtained and immediately sold in connection with the North Dakota Gathering and Processing Assets acquisition.
(b)
Amounts may not recalculate due to rounding of dollar and volume information.

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

 
Period Ended
 
December 31, 2017 (a)
Segment Operating Income
$
15

Add back:
 
Operating expenses (excluding depreciation and amortization)
15

Depreciation and amortization expenses
5

General and administrative expenses
3

Subtract:
 
Other wholesale revenues
(15
)
Wholesale Fuel Sales Margin
$
23

Divided by Total Volumes for the Period:
 
Fuel sales volumes (millions of gallons)
722

Average Wholesale Fuel Sales Margin per Gallon (b)

3.0
¢

(a)
Adjusted to include the historical results of the Predecessors. The 2017 period only includes the results beginning June 1, 2017.
(b)
Amounts may not recalculate due to rounding of dollar and volume information.

 
 
December 31, 2017 | 53

Management’s Discussion and Analysis

Capital Resources and Liquidity

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

Equity Overview

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

Unit Issuance
We closed a registered public offering of 5,000,000 common units representing limited partner interests at a public offering price of $56.19 per unit on February 27, 2017. The net proceeds of $281 million were used to repay borrowings outstanding under our Revolving Credit Facility and for general partnership purposes. Also, general partner units of 101,980 were issued for proceeds of $6 million.

In connection with the WNRL Merger, we issued 15,182,996 publicly held common units and 14,853,542 common units held by Andeavor. In addition, on October 30, 2017, we issued 78,000,000 of our common units to TLGP in connection with the IDR/GP Transaction and converted our general partner units into non-economic general partner units.

Issuance of Preferred Units
On December 1, 2017, we issued and sold 600,000 Preferred Units, at a price to