10-K 1 a2016form10-k.htm 10-K Document



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
 
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
¨
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 1-31219                    
 
 SUNOCO LOGISTICS PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
23-3096839
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
3807 West Chester Pike, Newtown Square, PA
 
19073
(Address of principal executive offices)
 
(Zip Code)
Registrant's telephone number, including area code: (866) 248-4344
 
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Units representing limited partner 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  ý    No  ¨
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  ¨    No  ý
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  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 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  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 of this Form 10-K.  ¨
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 definition of "large accelerated filer," "accelerated filer," "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý
 
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
¨
(Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10 percent or more of the Common Units outstanding (including the General Partner of the registrant, Sunoco Partners LLC, as if they may be affiliates of the registrant)) was $6.5 billion as of June 30, 2016, based on $28.75 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date. At February 22, 2017, the number of the registrant's Common and Class B Units outstanding were 322,388,550 and 9,416,196, respectively.
DOCUMENTS INCORPORATED BY REFERENCE: NONE







TABLE OF CONTENTS
 
 
 
 
 
PART I
ITEM 1.
BUSINESS
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 SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES
ITEM 6.
SELECTED FINANCIAL DATA
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A.
CONTROLS AND PROCEDURES
ITEM 9B.
OTHER INFORMATION
 
 
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 SECURITYHOLDER 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







Forward-Looking Statements
This annual report on Form 10-K discusses our goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition, or states other information relating to us, based on the current beliefs of our management as well as assumptions made by, and information currently available to, our management.
Words such as "may," "anticipates," "believes," "expects," "estimates," "planned," "scheduled" or similar phrases or expressions identify forward-looking statements. Although we believe these forward-looking statements are reasonable, they are based upon a number of assumptions, any or all of which may ultimately prove to be inaccurate. These statements are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results projected, forecasted, estimated or budgeted, including, but not limited to the following:
Our ability to successfully consummate announced acquisitions, mergers or expansions and integrate them into our existing business operations;
Delays related to construction of, or work on, new or existing facilities and the issuance of applicable permits;
Changes in the supply of, or demand for crude oil, natural gas liquids ("NGLs") and refined products that impact demand for our pipeline, terminalling and storage services;
Changes in the short-term and long-term demand for crude oil, NGLs and refined products we buy and sell;
An increase in the competition encountered by our pipelines, terminals and acquisition and marketing operations;
Changes in the financial condition or operating results of joint ventures or other holdings in which we have an equity ownership interest;
Changes in the general economic conditions in the United States;
Changes in laws and regulations to which we are subject, including federal, state, and local taxes, safety, environmental and employment laws;
Changes in regulations governing the composition of the products that we transport, terminal and store;
Improvements in energy efficiency and development of technology resulting in reduced demand for refined petroleum products;
Our ability to manage growth and/or control costs;
The effect of changes in accounting principles and tax laws, and interpretations of both;
Global and domestic economic repercussions, including disruptions in the crude oil, NGLs and refined petroleum products markets, from terrorist activities, international hostilities and other events, and the government's response thereto;
Changes in the level of operating expenses and hazards related to operating our facilities (including equipment malfunction, explosions, fires, spills and the effects of severe weather conditions);
The occurrence of operational hazards or unforeseen interruptions for which we may not be adequately insured;
The age of, and changes in the reliability and efficiency of our operating facilities;
Changes in the expected level of capital, operating, or remediation spending related to environmental matters;
Changes in insurance markets resulting in increased costs and reductions in the level and types of coverage available;
Risks related to labor relations and workplace safety;
Non-performance by or disputes with major customers, suppliers or other business partners;
Changes in our tariff rates implemented by federal and/or state government regulators;
The amount of our debt, which could make us vulnerable to adverse general economic and industry conditions, limit our ability to borrow additional funds, place us at competitive disadvantages compared to competitors that have less debt, or have other adverse consequences;
Restrictive covenants in our credit agreements;
Changes in our, or our general partner's, credit ratings, as assigned by ratings agencies;
The condition of the debt and equity capital markets in the United States, and our ability to raise capital in a cost-effective way;
Performance of financial institutions impacting our liquidity, including those supporting our credit facilities;
The effectiveness of our risk management activities, including the use of derivative financial instruments to hedge commodity risks;
Changes in interest rates on our outstanding debt, which could increase the costs of borrowing; and
The costs and effects of legal and administrative claims and proceedings against us or any entity in which we have an ownership interest, and changes in the status of, or the initiation of new litigation, claims or proceedings, to which we, or any entity in which we have an ownership interest, are a party.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement, whether as a result of new information or future events.



1



PART I
As used in this document, unless the context otherwise indicates, the terms "we," "us," and "our" means Sunoco Logistics Partners L.P. ("SXL" or the "Partnership"), one or more of our operating subsidiaries, or all of them as a whole.
 
ITEM 1.
BUSINESS
(a) General Development of Business
We are a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, natural gas liquids ("NGLs") and refined products. Sunoco Partners LLC, a Pennsylvania limited liability company and the general partner of Sunoco Logistics Partners, is a consolidated subsidiary of Energy Transfer Partners, L.P., a publicly traded Delaware limited partnership ("ETP"). The principal executive offices of Sunoco Partners LLC, our general partner, are located at 3807 West Chester Pike, Newtown Square, PA 19073 (telephone (866) 248-4344). Our website address is www.sunocologistics.com.
During the fourth quarter 2015, we realigned our reporting segments as a result of the continued investment in our organic growth capital program which has served to increase the integration that exists between our assets that service each commodity. This has also resulted in a shift in Management's strategic decision making process, resource allocation methodology, and assessment of our financial results. The updated reporting segments are: Crude Oil, Natural Gas Liquids and Refined Products. The new segmentation provides our investors with a more meaningful view of our business that is consistent with that of Management. For the purpose of comparability, all prior year segment disclosures have been recast to conform to the current year presentation. Such recasts had no impact on previously reported consolidated earnings.
On November 20, 2016, we and our general partner, Sunoco Partners LLC ("SXL GP"), a Pennsylvania limited liability company, entered into an Agreement and Plan of Merger (the "Merger Agreement") with ETP, together with Energy Transfer Partners GP, L.P. ("ETP GP"), a Delaware limited partnership and the general partner of ETP, and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. ("ETE"), a Delaware limited partnership and indirect parent entity of ETP, ETP GP, the Partnership and SXL GP. Upon the terms and subject to the conditions set forth in the Merger Agreement, a wholly-owned subsidiary of SXL will merge with ETP (the "Merger"), with ETP continuing as the surviving entity and a wholly-owned subsidiary of SXL. Concurrently with the Merger, SXL GP will merge with ETP GP, with ETP GP continuing as the surviving entity and becoming the general partner of SXL. Following the recommendation of the conflicts committee (the "ETP Conflicts Committee") of the board of directors of ETP's managing general partner (the "ETP Board"), the ETP Board approved and agreed to submit the Merger Agreement to a vote of ETP unitholders and to recommend that ETP's unitholders adopt the Merger Agreement. Following the recommendation of the conflicts committee of the board of directors of SXL GP, the board of directors of SXL GP approved the Merger Agreement. The Merger is expected to close in April 2017.
Effective at the time of the Merger, all SXL units, 67.1 million common and 9.4 million Class B, currently held by ETP will be retired. The existing incentive distribution right ("IDR") provisions in the SXL Partnership Agreement will continue to be in effect, and ETE will own the IDRs of SXL following the closing of the transaction. As part of this transaction, ETE has agreed to continue to provide all the IDR subsidies that are currently in effect for both SXL and ETP. In addition, our 364-Day credit facility is expected to be terminated and repaid in connection with the Merger. Also effective at the time of the Merger, each common unit representing a limited partner interest in ETP issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time of the merger will be converted into the right to receive 1.50 common units representing limited partner interests in SXL (the "SXL Common Units") (the "Merger Consideration"). Each Class E Unit of ETP, each Class G Unit of ETP, each Class I Unit of ETP, each Class J Unit of ETP and each Class K Unit of ETP, if any, issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time of the Merger will be converted into the right to receive a corresponding unit in SXL with the same rights, preferences, privileges, powers, duties and obligations as such existing ETP unit had immediately prior to the Merger. The corresponding units in SXL will be issued pursuant to the Fourth Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., which will be executed at the effective time.
(b) Financial Information about Segments
See Part II, Item 8. "Financial Statements and Supplementary Data."


2



(c) Narrative Description of Business
We are a Delaware limited partnership which is principally engaged in the transport, terminalling and storage of crude oil, NGLs and refined products. In addition to logistics services, we also own acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, NGLs and refined products. Our portfolio of geographically diverse assets earns revenues in 37 states located throughout the United States. Our reporting segments are as follows:
The Crude Oil segment provides transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeast United States. Included within the segment is approximately 6,100 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States and equity ownership interests in two crude oil pipelines. Our crude oil terminalling services operate with an aggregate storage capacity of approximately 33 million barrels, including approximately 26 million barrels at our Gulf Coast terminal in Nederland, Texas, approximately 3 million barrels at our Fort Mifflin terminal complex in Pennsylvania and approximately 2 million barrels at our newly acquired Midland, Texas terminal. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets, our proprietary fleet of crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the mid-continent United States.
The Natural Gas Liquids segment transports, stores, and executes acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGLs markets. The segment contains approximately 900 miles of NGLs pipelines, primarily related to our Mariner systems located in the northeast and southwest United States. Terminalling services are facilitated by approximately 5 million barrels of NGLs storage capacity, including approximately 1 million barrels of storage at our Nederland, Texas terminal facility and 3 million barrels at our Marcus Hook, Pennsylvania terminal facility (the "Marcus Hook Industrial Complex"). This segment also carries out our NGLs blending activities, including utilizing our patented butane blending technology.
The Refined Products segment provides transportation and terminalling services, through the use of approximately 1,800 miles of refined products pipelines and approximately 40 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 million barrels of refined products storage capacity. The Refined Products segment includes our Eagle Point facility in New Jersey, which has approximately 6 million barrels of refined products storage capacity. The segment also includes our equity ownership interests in four refined products pipeline companies. The segment also performs terminalling activities at our Marcus Hook Industrial Complex. The Refined Products segment utilizes our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions of the United States.
Our primary business strategies focus on generating stable cash flows, increasing pipeline and terminal throughput, utilizing our acquisition and marketing assets to maximize value, pursuing economically accretive organic growth opportunities and improving operational efficiencies. We believe that the effective execution of these strategies will result in continued increases in distributions to our unitholders.
We continue to expand our business with the November 2016 purchase of Vitol Inc.'s ("Vitol") crude oil assets in the Midland basin, commencement of operations on several organic growth projects related to our three commodity strategies, and continued capital investment in our equity ownership interests in crude oil pipeline projects, which provide connectivity with our existing pipeline and terminalling assets upon commencement of operations. We also continued to expand our NGLs platform with continued progress on the previously announced Mariner projects.
We are subject to competition from third parties in all of our operations. In addition, our businesses make use of a portfolio of complementary crude oil, NGLs and refined products pipelines, terminalling, and acquisition and marketing assets. While this integration creates opportunities and synergies within our operations, assets are sometimes repurposed among our business lines to maximize their utility and profitability. We will continue to utilize our assets in a manner that favors our consolidated results.





3



Crude Oil
Our Crude Oil segment consists of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets.
We completed the following transactions in the Crude Oil segment since December 31, 2011:
In November 2016, we acquired an integrated crude oil business in West Texas from Vitol. The acquisition provides us with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50 percent interest in the SunVit Pipeline LLC ("SunVit"), which increased our overall ownership of SunVit to 100 percent. SunVit connects the Midland terminal to our Permian Express 2 pipeline, a key takeaway to bring Permian crude oil to multiple markets. SunVit was renamed Permian Express Terminal LLC ("PET") in December 2016.
In October 2015, we obtained a 30 percent ownership interest in the Bakken pipeline project through acquisition of an ownership interest in the Bakken Holdings Company LLC. The Bakken pipeline consists of existing and newly constructed pipelines that are expected to provide aggregate takeaway capacity of approximately 450 thousand barrels per day ("bpd") of crude oil from the Bakken/Three Forks production area in North Dakota to key refinery and terminalling hubs in the midwest and Gulf Coast, including our Nederland terminal. The ultimate takeaway capacity target for the Bakken pipeline is 570 thousand bpd. The project is jointly owned by ETP and Phillips 66. Commercial operations are expected to commence in the second quarter 2017.
In February 2017, ETP and Sunoco Logistics completed the sale of a 36.75 percent interest in the Bakken Pipeline project for $2 billion in cash to MarEn Bakken Company LLC, an entity jointly owned by Enbridge Energy Partners, L.P. and MPLX LP. Sunoco Logistics received $800 million for its interest, and proceeds from the sale were used to pay down debt and will be used to help fund our expansion capital program. As a result of the sale, our interest in the Bakken Pipeline project is 15.3 percent.
In July 2015, we obtained a 30 percent ownership interest in the Bayou Bridge Pipeline, LLC ("Bayou Bridge"), which consists of newly constructed pipeline that delivers crude oil from Nederland, Texas to refinery markets in Louisiana. Commercial operations from Nederland, Texas to Lake Charles, Louisiana commenced in the second quarter 2016, with continued progress on an extension of the pipeline segment to St. James, Louisiana, which is expected to commence operations in the fourth quarter 2017. The Bayou Bridge pipeline is a joint project with ETP and Phillips 66, and we are the operator of the pipeline.
In December 2014 and January 2015, we acquired an additional 39.7 percent ownership interest in the West Texas Gulf Pipe Line Company ("West Texas Gulf") which originates in Colorado City and delivers to destinations in Goodrich and Longview, Texas. The acquisition resulted in a wholly-owned interest in this strategic crude oil pipeline.
In May 2014, we acquired a crude oil purchasing and marketing business from EDF Trading North America, LLC ("EDF"). The purchase consisted of a crude oil acquisition and marketing business and related assets which handle 20 thousand bpd. The acquisition included a promissory note that was convertible to an equity interest in the Price River Terminal rail facility.
In May 2014, we acquired a 55 percent economic and voting interest in Price River Terminal, LLC ("PRT"), a rail facility in Wellington, Utah. As the Partnership acquired a controlling financial interest in PRT, the entity is reflected as a consolidated subsidiary of the Partnership from the acquisition date. The terms of the acquisition provide PRT's noncontrolling interest holders the option to sell their interests to the Partnership at a price defined in the purchase agreement.
In February 2017, we formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil. We contributed our Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Our ownership percentage, upon formation, is approximately 85 percent. Upon commencement of operations on the Bakken pipeline, we will contribute our investment in the project, with a corresponding increase in our ownership percentage in PEP. We maintain a controlling financial and voting interest in PEP and are the operator of all of the assets contributed to the joint venture. As such, PEP will be reflected as a consolidated subsidiary of our operating results, included within the Crude Oil segment. ExxonMobil's interest will be reflected as a noncontrolling interest in our consolidated balance sheets.


4



Crude Oil Pipelines
The crude oil pipelines consist of approximately 6,100 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including our wholly-owned interests in West Texas Gulf and PET, and a controlling financial interest in Mid-Valley Pipeline Company ("Mid-Valley"). Additionally, we have equity ownership interests in two crude oil pipelines. Our pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the Federal Energy Regulatory Commission ("FERC") and other state regulatory agencies, as applicable.
The table below summarizes the average daily number of barrels of crude oil and other feedstocks transported on our crude oil pipelines in each of the years presented:
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
Crude oil pipelines throughput (thousands of bpd) (1) (2)
 
2,423

 
2,225

 
2,125

(1) 
Prior period pipeline throughput amounts have been restated to conform to current presentation.
(2) 
Excludes amounts attributable to equity ownership interests which are not consolidated. Throughputs related to the acquisition from Vitol have been included from the acquisition date.
Southwest United States Pipelines
Our southwest pipelines include crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma. This includes our Permian Express 2 pipeline project which provides takeaway capacity from the Permian Basin, with origins in multiple locations in Western Texas: Midland, Garden City and Colorado City. With an initial capacity of approximately 200 thousand barrels per day, Permian Express 2 began delivery to multiple refiners and markets in the third quarter 2015. Our fourth quarter 2016 acquisition of a West Texas crude oil system from Vitol and the remaining ownership interest in PET facilitates connection of our Permian Express 2 pipeline to terminal assets in Midland and Garden City, Texas.
In the third quarter 2016, we commenced operations on the Delaware Basin Extension and Permian Longview and Louisiana Extension pipeline projects. The Delaware Basin Extension pipeline project provides shippers with new takeaway capacity from the rapidly growing Delaware Basin area in New Mexico and West Texas to Midland, Texas. The project has initial capacity to transport approximately 100 thousand barrels per day. The Permian Longview and Louisiana Extension pipeline project provides takeaway capacity for approximately 100 thousand additional barrels per day out of the Permian Basin at Midland, Texas to be transported to the Longview, Texas area as well as destinations in Louisiana utilizing a combination of our proprietary crude oil system as well as third party pipelines.
We own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Midwest United States Pipelines
We own a controlling financial interest in the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, and Ohio, and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge Mainline Pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon's Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan.




5



Crude Oil Terminals
The table below summarizes the total average daily crude oil throughput at our crude oil terminals in each of the years presented:
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
Crude oil terminals throughput (thousands of bpd) (1)
 
1,552

 
1,401

 
1,403

(1)     Throughput related to the Vitol acquisition has been included from the acquisition date.
Nederland
The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil and bunker oils (used for fueling ships and other marine vessels), and has a total crude oil storage capacity of approximately 26 million barrels in approximately 150 aboveground storage tanks with individual capacities of up to 660 thousand barrels.
The Nederland terminal can receive crude oil at each of its five ship docks and four barge berths. The five ship docks are capable of receiving over 2 million barrels of crude oil per day. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of third-party pipelines, including the Department of Energy ("DOE"). The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve's West Hackberry caverns at Hackberry, Louisiana and Big Hill near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million barrels.
The Nederland terminal can deliver crude oil via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million barrels of crude oil per day to our crude oil pipelines or a number of third-party pipelines, including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin
The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated at the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 thousand barrels. Crude oil enters the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class ("VLCC") tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a crude oil storage terminal for the Philadelphia refinery, which is operated by Philadelphia Energy Solutions ("PES") under a joint venture with an affiliate of ETP. This facility has a total storage capacity of approximately 3 million barrels. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines. The tank farm then stores the crude oil and transports it to the Philadelphia refinery via our pipelines.
Eagle Point
The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil to outbound ships and barges. The tank farm has a total active crude oil storage capacity of approximately 1 million barrels and can receive crude oil via barge and rail, and deliver via barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland
The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million barrels of crude oil storage, a combined 14 lanes of truck loading and unloading, and will provide access to the Permian Express 2 transportation system.


6



Crude Oil Acquisition and Marketing
These activities include the acquisition and marketing of crude oil, primarily in the mid-continent United States. The operations are conducted using our assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets. Specifically, our crude oil acquisition and marketing activities include:
purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
buying and selling crude oil of different grades, at different locations in order to maximize value;
transporting crude oil using our pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
The crude oil acquisition and marketing activities generate substantial revenue and cost of products sold as a result of the significant volume of crude oil bought and sold. While the absolute price levels of crude oil significantly impact revenue and cost of products sold, such price levels normally do not bear a relationship to gross profit. As a result, period-to-period variations in revenue and cost of products sold are not generally meaningful in analyzing the variation in gross profit for the crude oil acquisition and marketing activities. The operating results are dependent on our ability to sell crude oil at a price in excess of our aggregate cost. Our operations are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices. Generally, we expect a base level of earnings from our crude oil acquisition and marketing activities that may be optimized and enhanced when there is a high level of market volatility, favorable basis differentials, and/or a steep contango or backwardated structure. Although we implement risk management processes to provide general stability in our margins, these margins are not fixed and will vary from period to period.
We mitigate most of our pricing risk on purchase contracts by selling crude oil for an equal term on a similar pricing basis. We also mitigate most of our volume risk by entering into sales agreements, generally at the same time that purchase agreements are executed, at similar volumes. As a result, volumes sold are generally equal to volumes purchased. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on crude oil price changes, as these activities could expose us to significant losses.
In November 2016, we purchased a crude oil acquisition and marketing business from Vitol, with operations based in the Permian Basin, Texas. Included in the acquisition was a significant acreage dedication from an investment-grade Permian producer.
Crude Oil Purchases and Exchanges
In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the producer treats the crude oil to remove water, sediment, and other contaminants and then moves it to an on-site storage tank. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. The crude oil in the producer's tanks is then either delivered directly or transported via truck to our pipeline or to a third-party pipeline. The trucking services are performed either by our truck fleet or a third-party trucking operation.
Crude oil purchasers who buy from producers compete on the basis of price and the ability to provide highly responsive services. Our management believes that our ability to offer competitive pricing and high-quality field and administrative services to producers is a key factor in our ability to maintain our volume of lease purchased crude oil and to obtain new volume.
We also enter into exchange agreements to enhance margins throughout the acquisition and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more nearly matches our delivery requirements or the preferences of our refinery customers, we exchange our physical crude oil with third parties. Generally, we enter into exchanges to acquire crude oil of a desired quality in exchange for a common grade crude oil or to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs.
Generally, we enter into contracts with producers at market prices for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. For the year ended December 31, 2016, we purchased approximately 316 thousand barrels per day, from approximately 3 thousand producers, who operate approximately 60 thousand active leases. We also undertook 562 thousand barrels per day of exchanges and bulk purchases during the same period.

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The following table shows our average daily volume for crude oil lease purchases and sales, and other exchanges and bulk purchases in each of the years presented:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands of bpd)
Lease purchases:
 
 
 
 
 
 
Available for sale
 
310

 
361

 
378

Exchanged
 
6

 
4

 
14

Other exchanges and bulk purchases
 
562

 
491

 
481

Total Purchases
 
878

 
856

 
873

 
 
 
 
 
 
 
Bulk Sales
 
438

 
471

 
483

Exchanges:
 
 
 
 
 
 
Purchased at the lease
 
6

 
4

 
14

Other
 
428

 
369

 
372

Total Sales
 
872

 
844

 
869

Crude oil commodity prices have historically been volatile and cyclical. Profitability from our acquisition and marketing activities is dependent on our ability to sell crude oil at prices in excess of our aggregate cost. Our operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices. Generally, we expect a base level of earnings from our acquisition and marketing activities, which may be optimized and enhanced when there is a high level of market volatility. Integration between our crude oil acquisition and marketing assets, pipelines, and terminal facilities allows us to further improve upon earnings during periods when there are favorable basis differentials between various types of products. Additionally, we are able to increase our base level of earnings when there is a steep contango or backwardated market structure.
During periods when supply exceeds the demand for crude oil in the near term, the market for crude oil is often in contango, meaning that the price of crude oil for future deliveries is higher than the price for current deliveries. A contango market generally has a negative impact on our lease gathering margins, but is favorable to commercial strategies associated with tankage. Access to our crude oil storage facilities during a contango market allows us to improve our lease gathering margins by simultaneously purchasing crude oil inventories at current prices for storage and selling forward at higher prices for future delivery.
When there is a higher demand than supply of crude oil in the near term, the market is backwardated, meaning that the price of crude oil for future deliveries is lower than the price for current deliveries. A backwardated market has a positive impact on our lease gathering margins because crude oil gatherers can capture a premium for prompt deliveries. In this environment, there is little incentive to store crude oil, as current prices are above delivery prices in the futures markets. In a backwardated market, increased lease gathering margins provide an offset to reduced use of storage capacity.
The periods between a backwardated market and a contango market are referred to as transition periods. Depending on the overall duration of these transition periods, how we have allocated our assets to particular strategies and the time length of our crude oil purchase and sale contracts and storage lease agreements, these transition periods may have either an adverse or beneficial effect on our aggregate segment profit. A prolonged transition from a backwardated market to a contango market, or vice versa (essentially, a market without pronounced backwardation or contango), represents the most difficult environment for our marketing activities.
Crude Oil Trucking
We own approximately 150 crude oil truck unloading facilities in the mid-continent United States with the majority located on our pipeline systems. Approximately 610 crude oil truck drivers are employed by an affiliate of our general partner and we own and operate a proprietary fleet of approximately 370 crude oil transport trucks. The crude oil truck drivers pick up crude oil at producer sites and transport it to both our truck unloading facilities and third-party unloading facilities for shipment on our pipelines and third-party pipelines. Third-party trucking firms are also retained to transport crude oil to certain facilities.




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Natural Gas Liquids
Our Natural Gas Liquids segment transports, stores, and executes acquisition and marketing activities utilizing an integrated network of pipeline assets, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.
Since December 31, 2011, we completed the following acquisitions in our Natural Gas Liquids segment:
In April 2013, we acquired Sunoco's Marcus Hook Industrial Complex and related assets. The acquisition included terminalling and storage assets with a capacity of approximately 2 million barrels of NGLs storage capacity in underground caverns.
NGLs Pipelines
This segment includes approximately 900 miles of NGLs pipelines, primarily related to our Mariner systems in the northeast and southwest United States.
The table below summarizes the average daily number of barrels of NGLs transported on our pipelines in each of the years presented:
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
NGLs pipelines throughput (thousands of bpd)
 
277

 
209

 
33

Our Mariner East project transports NGLs from the Marcellus and Utica Shale areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consists of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 thousand barrels per day for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the third quarter 2017.
In the fourth quarter 2014, we commenced operations on the Mariner South pipeline. The Mariner South pipeline is part of a joint project with Lone Star NGL LLC ("Lone Star") to deliver export-grade propane and butane products from Lone Star's Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas. The pipeline has a capacity of approximately 200 thousand barrels per day and can be scaled depending on shipper interest.
The Mariner West pipeline provides transportation of ethane products from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter 2013, with capacity to transport approximately 50 thousand barrels per day of NGLs and other products.
Revenues on our NGLs pipelines are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with FERC and other state and Canadian regulatory agencies, as applicable.
NGLs Terminals
Our NGLs terminals generate revenue primarily by charging fees based on throughput, blending services and storage.
The table below summarizes the total average daily throughput for our NGLs terminals in each of the years presented:
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
NGLs terminals throughput (thousands of bpd)
 
235

 
184

 
40

Nederland
In addition to crude oil activities, the Nederland terminal also provides approximately 1 million barrels of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be delivered via ship.



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Marcus Hook Industrial Complex
We acquired the Marcus Hook Industrial Complex from an affiliated entity in the second quarter 2013. The acquisition included terminalling and storage assets, with a capacity of approximately 3 million barrels of NGL storage capacity in underground caverns, and related commercial agreements. The facility can receive NGLs via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for our Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
Inkster
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million barrels of NGLs. We use the Inkster terminal's storage in connection with our Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
NGLs Acquisition & Marketing
Our NGLs acquisition and marketing activities include the acquisition, blending, marketing and selling of such products at our various terminals and third-party facilities. Since the acquisition of our butane blending business in 2010, we have continued to expand our butane blending service platform by installing our blending technology at certain of our terminals and third-party facilities, as well as the continued development of the Marcus Hook Industrial Complex. The operating results of our NGLs acquisition and marketing activities are dependent on our ability to execute sales in excess of the aggregate cost, and therefore we structure our acquisition and marketing operations to optimize the sources and timing of purchases and minimize the transportation and storage costs. In order to manage exposure to volatility in the price of NGLs, our policy is to (i) only purchase products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. However, we do utilize a seasonal hedge program involving swaps, futures and other derivative instruments to mitigate the risk associated with unfavorable market movements in the price of NGLs products. These derivative contracts act as a hedging mechanism against the volatility of prices.





















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Refined Products
Our Refined Products segment provides transportation and terminalling services using an integrated network of pipeline assets and refined products terminals, which are also utilized to facilitate acquisition and marketing activities. The segment also includes equity ownership interests in four refined products pipelines.
Since December 31, 2011, we completed the following acquisitions in our Refined Products segment:
In March 2014 and August 2016, we exercised rights to acquire additional 3.9 and 1.7 percent ownership interests, respectively, in Explorer Pipeline Company ("Explorer"), increasing our overall ownership interest from 9.4 to 15.0 percent as a result of the transactions.
Refined Products Pipelines
We own and operate approximately 1,800 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. The segment includes our controlling financial interest in Inland.
The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by our refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term.
The products transported in these pipelines include multiple grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on our products pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
During the first quarter 2015, we commenced operations on the Allegheny Access pipeline project, which transports refined products from the midwest to eastern Ohio and western Pennsylvania markets at a capacity of up to 85 thousand barrels per day with the possibility to increase capacity to meet further demands.
The following table shows the average shipments on the refined products pipelines system in each of the years presented:
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
Refined products pipelines throughput (thousands of bpd) (1) (2)
 
599

 
518

 
481

(1) 
Excludes amounts attributable to equity ownership interests which are not consolidated.
(2) 
Prior period pipeline throughput amounts have been restated to conform to current presentation.
In addition to our consolidated pipeline assets, we own equity interests in several common carrier refined products pipelines, summarized in the following table:
Pipeline
 
SXL Equity Ownership
 
Approximate Pipeline Mileage
Explorer Pipeline Company (1)
 
15.0%
 
1,850
Yellowstone Pipe Line Company (2)
 
14.0%
 
700
West Shore Pipe Line Company (3)
 
17.1%
 
650
Wolverine Pipe Line Company (4)
 
31.5%
 
700
(1) 
The system, which is operated by Explorer employees, originates from the refining centers of Beaumont, Port Arthur and Houston, Texas, and extends to Chicago, Illinois, with delivery points in the Houston, Dallas/Fort Worth, Tulsa, St. Louis, and Chicago areas. Explorer charges market-based rates for all its tariffs.
(2) 
The system, which is operated by Phillips 66, originates from the Billings, Montana refining center and extends to Moses Lake, Washington, with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.
(3) 
The system, which is operated by Buckeye Partners, L.P., originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin, with delivery points along the way. West Shore charges market-based tariff rates in the Chicago area.
(4) 
The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven and Bay City, Michigan, with delivery points along the way. Wolverine charges market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond and Lockport destinations.


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Refined Products Terminals
Our active refined products terminals receive refined products from pipelines, barges, railcars, and trucks and distribute them to third parties and certain of our affiliates, who in turn deliver them to end-users and retail outlets. Terminals play a key role in moving product to the end-user markets by providing the following services: storage; distribution; blending to achieve specified grades of gasoline and middle distillates; and other ancillary services that include the injection of additives and the filtering of jet fuel. These terminals facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Of our approximately 40 refined products terminals, each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day. This automated system provides controls over allocations, credit, and carrier certification.
Our refined products terminals derive revenues from terminalling fees paid by customers. A fee is charged for receiving products into the terminal and delivering them to trucks, barges, or pipelines. In addition to terminalling fees, our refined products terminals generate revenues by charging customers fees for blending services, including certain ethanol and biodiesel blending, injecting additives, and filtering jet fuel. Our refined products pipelines provide supply to the majority of our refined products terminals, with third-party pipelines and barges supplying the remainder.
The table below summarizes the total average daily throughput for the refined products terminals in each of the years presented: 
 
 
Year Ended December 31,
  
 
2016
 
2015
 
2014
Refined products terminals throughput (thousands of bpd)
 
557

 
534

 
497


The following table outlines the number of active refined products marketing terminals and storage capacity by state:
State
 
Number of Terminals
 
Storage Capacity
 
 
 
 
(thousands of barrels)
Indiana
 
1

 
206

Louisiana
 
1

 
162

Maryland
 
1

 
709

Massachusetts
 
1

 
1,204

Michigan
 
3

 
744

New Jersey
 
3

 
652

New York (1)
 
4

 
1,009

Ohio
 
7

 
1,001

Pennsylvania
 
13

 
1,500

Texas
 
4

 
550

Virginia
 
1

 
406

Total
 
39

 
8,143

(1) 
We have a 45 percent ownership interest in a terminal at Inwood, New York and a 50 percent ownership interest in a terminal that we operate in Syracuse, New York. The storage capacities included in the table represent the proportionate share of capacity attributable to our ownership interests in these terminals.
Eagle Point
In addition to crude oil services, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million barrels, and provides customers with access to the facility via barge and pipeline. The terminal can deliver via barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.





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Marcus Hook Industrial Complex
The Marcus Hook Industrial Complex can receive refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. The terminal has a total active refined products storage capacity of approximately 2 million barrels.
Marcus Hook Tank Farm
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million barrels. The tank farm historically served Sunoco's Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco's exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on our refined products pipelines.
Refined Products Acquisition and Marketing
Our refined products acquisition and marketing activities include the acquisition, marketing and selling of bulk refined products such as gasoline products and distillates. These activities utilize our refined products pipeline and terminal assets, as well as third-party assets and facilities. The operating results of our refined products acquisition and marketing activities are dependent on our ability to execute sales in excess of the aggregate cost, and therefore we structure our acquisition and marketing operations to optimize the sources and timing of purchases and minimize the transportation and storage costs. In order to manage exposure to volatility in refined products prices, our policy is to (i) only purchase products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. However, we do utilize a hedge program involving swaps, futures and other derivative instruments to mitigate the risk associated with unfavorable market movements in the price of refined products. These derivative contracts act as a hedging mechanism against the volatility of prices.
  

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Pipeline and Terminal Control Operations
Almost all of our pipelines are operated via satellite, microwave, and frame relay communication systems from central control rooms located in Sugar Land, Texas and Montello, Pennsylvania. The Sugar Land control center primarily monitors and controls our crude oil pipelines, and the Montello control center primarily monitors and controls our NGLs and refined products pipelines. The Nederland terminal has its own control center.
The control centers operate with Supervisory Control and Data Acquisition, or SCADA, systems that continuously monitor real time operational data, including throughput, flow rates, and pressures. In addition, the control centers monitor alarms and throughput balances. The control centers operate remote pumps, motors and valves associated with the delivery of throughput products. The computer systems are designed to enhance leak-detection capabilities, sound automatic alarms if operational conditions occur outside of pre-established parameters, and provide for remote-controlled shutdown of pump stations on the pipelines. Pump stations and meter-measurement points along our pipelines are linked by satellite or telephone communication systems for remote monitoring and control, which reduces the requirement for full-time on-site personnel at most of these locations.

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Competition
Pipeline Operations
Our pipelines face competition from a number of sources, including major oil companies and other common carrier pipelines. Generally, pipelines are the lowest-cost method for long-haul commodity movements. Therefore, the most significant competitors for large volume shipments are other pipelines. Competition among pipelines is based primarily on access to commodity supply, market demand, and transportation charges offered for commodity movements. In addition, in areas where additional infrastructure is needed to accommodate production needs, we compete with other pipeline providers to offer the necessary transportation services to meet market demand. Our management believes that high capital requirements, environmental considerations, and the difficulty in acquiring rights-of-way and related permits make it difficult for other companies to build competing pipelines in certain areas served by our pipelines. As a result, competing pipelines are likely to be built only in those cases in which strong market demand and attractive tariff rates support additional capacity in an area.
In addition to competition from other pipelines, we face competition from trucks and rail that deliver products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, these sources of transportation compete effectively for incremental and marginal volume in many areas where such means of transportation are prevalent.
Terminalling Services
Terminal facilities compete based on pricing, accessibility to supply and distribution locations and flexibility of the terminal facility's service offering. Our terminal facilities service the crude oil, NGLs and refined products markets in the southwest, midwest and northeast United States.
Throughput at our Nederland terminal includes both crude oil and NGLs. The primary competitors of the Nederland terminal are its refinery customers' docks and other terminal facilities located in the Beaumont, Texas area with similar capabilities to distribute these commodities to the end-user markets.
Our Marcus Hook Industrial Complex has the capability to handle the processing, storage and distribution of crude oil, NGLs and refined products and has access to local, domestic and waterborne markets. An increase in competition for the facility could result from the development of a facility providing similar service offerings.
Our refined products marketing terminals located in the northeast, midwest and southwest United States compete with other independent terminals on price, versatility, and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies, and distribution companies with marketing and trading activities.
The majority of the throughput at our crude oil terminal facilities in the northeast relates to refining operations at PES's Philadelphia refinery. In 2012, we entered into a 10-year agreement to provide terminalling services to PES at the Fort Mifflin terminal complex. For further information, see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Related Parties."
Acquisition and Marketing Activities
Our competitors for our acquisition and marketing of crude oil, NGLs and refined products include other petroleum products pipeline companies, major integrated oil companies and their marketing affiliates, independent gatherers, banks that have established trading platforms, and brokers and marketers of varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control or have access to greater supplies of the specific commodities that we market. Competitive factors that impact our acquisition and marketing activities include price and contract flexibility, regional pricing differentials, availability of commodity supply and demand, quantity and quality of services offered, and accessibility to end markets. Our acquisition and marketing of NGLs includes butane blending services. Our patents provide us with the exclusive use and control over the technology utilized to provide these services to our customers.







15



Safety Regulation
A majority of our pipelines are subject to United States Department of Transportation ("DOT") regulations and to regulations under comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities.
DOT regulations require operators of hazardous liquid interstate pipelines to develop and follow a program to assess the integrity of all pipeline segments that could affect designated "high consequence areas," including: high population areas, drinking water and ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. We have prepared our own written Integrity Management Program, identified the line segments that could impact high consequence areas, and completed a full assessment of these segments as prescribed by the regulations.
We are confident that our pipeline operations are in substantial compliance with applicable DOT regulations and comparable state requirements. However, an increase in expenditures may be needed in the future to comply with higher industry and regulatory safety standards. Such expenditures cannot be estimated accurately at this time, but we do not believe they would likely have a material adverse effect relative to our results of operations, financial position or expected cash flows.
Environmental Regulation
General
Our operations are often subject to complex federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations which govern the handling and release of crude oil and other liquid hydrocarbon materials, some of which are discussed below. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. Our management believes we are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the legislative and regulatory trend has been to place increasingly stringent limitations on activities that may affect the environment.
There are also risks of accidental releases into the environment associated with our operations, such as releases of crude oil or hazardous substances from our pipelines or storage facilities. To the extent an event is not covered by our insurance policies, such accidental releases could subject us to substantial liabilities arising from emergency response, environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental laws or regulations.
Sunoco indemnifies us for 100 percent of all losses from environmental liabilities related to the assets contributed to SXL arising prior to, and asserted within 21 years of, February 8, 2002, the date of our initial public offering ("IPO"). Sunoco's share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the IPO date. For example, for a claim asserted during the twenty-third year after the closing of the IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on this indemnification from Sunoco. In addition, this indemnification applies to the following, purchased from Sunoco subsequent to the IPO: interests in the Mesa Pipeline System, Mid-Valley, West Texas Gulf, Inland, Marcus Hook Industrial Complex, as well as the Eagle Point Tank Farm and various other assets. Any remediation liabilities not covered by this indemnity will be our responsibility.
We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the contributed assets occurring after the IPO date and for environmental and toxic tort liabilities related to these assets to the extent Sunoco is not required to indemnify us. Total future costs for environmental remediation activities will depend upon, among other things, the extent of impact at each site; the timing and nature of required remedial actions; the technology available; and the determination of our liability at multi-party sites. As of December 31, 2016, all material environmental liabilities incurred by, and known to, us are either covered by the environmental indemnification or reserved for by us in our consolidated financial statements.







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Air Emissions
Our operations are subject to the Clean Air Act, as amended, and comparable state and local statutes. We will be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission related issues. In addition, the federal government has enacted regulations relating to restrictions on emissions of greenhouse gases ("GHG"). At this time, our operations do not fall under any of the current GHG regulations. While the effect of these current regulations will not impact our operations, the federal, regional or state laws or regulations limiting emissions of GHGs in the United States could adversely affect the demand for crude oil, NGLs or refined products transportation and storage services, as well as contribute to increased compliance costs or additional operating restrictions.
Our customers are also subject to, and similarly affected by, environmental regulations. These include federal and state actions to develop programs for the reduction of GHG emissions as well as proposals that would create a cap and trade system that would require companies to purchase carbon emission allowances for emissions at manufacturing facilities and emissions caused by the use of the fuels sold. In addition, the Environmental Protection Agency ("EPA") indicated that it intends to regulate carbon dioxide emissions. As a result of these regulations, our customers could be required to make significant capital expenditures, operate refineries at reduced levels, and pay significant penalties. It is uncertain what our customers' responses to these emerging issues will be. Those responses could reduce throughput in our pipelines and terminals, and impact our cash flows and ability to make distributions or satisfy debt obligations.
Hazardous Substances and Waste
In the course of ordinary operations, we may generate waste that falls within the Comprehensive Environmental Response, Compensation, and Liability Acts' ("CERCLA"), also known as Superfund, definition of a "hazardous substance" and, as a result, we may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on our maintenance capital expenditures and operating expenses to the extent not all are covered by the indemnity from Sunoco. For more information, please see "Environmental Remediation."
We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during our operating activities, will in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements than non-hazardous wastes. Any changes in the regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination.
We have not been identified by any state or federal agency as a potentially responsible party in connection with the transport and/or disposal of any waste products to third-party disposal sites.
Water
Our operations can result in the discharge of regulated substances, including crude oil, NGLs or refined products. The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. Where applicable, our facilities have the required discharge permits.
The Oil Pollution Act subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release. The Department of Transportation Pipeline Hazardous Materials Administration, the EPA, or various state regulatory agencies have approved our oil spill emergency response plans, and our management believes we are in substantial compliance with these laws.



17



In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Environmental Remediation
Contamination resulting from releases of crude oil, NGLs and refined products is not unusual within the petroleum pipeline industry. Historic releases along our pipelines, gathering systems, and terminals as a result of past operations have resulted in impacts to the environment, including soil and groundwater. Site conditions, including soil and groundwater, are being evaluated at a number of properties where operations may have resulted in releases of hydrocarbons and other wastes. Sunoco has agreed to indemnify us from environmental and toxic tort liabilities related to the assets contributed to the extent such liabilities existed or arose from operation of these assets prior to the closing of the February 2002 IPO and are asserted within 30 years after the closing of the IPO. This indemnity will cover the costs associated with performance of the assessment, monitoring, and remediation programs, as well as any related claims and penalties. See "Environmental Regulation-General."
We have experienced releases for which we are not covered by an indemnity from Sunoco, and for which we are responsible for necessary assessment, remediation, and/or monitoring activities. We have also purchased certain pipeline and terminal assets for which we assume remediation responsibilities. Our management estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these sites is not material in relation to our operations, financial position or cash flows at December 31, 2016. We have implemented an extensive inspection program to prevent releases of crude oil, NGLs or refined products into the environment from our pipelines, gathering systems, and terminals. Any damages and liabilities incurred due to future environmental releases from our assets have the potential to substantially affect our business and our ability to generate the cash flows necessary to make distributions or satisfy debt obligations.
Rate Regulation
General Interstate Regulation
Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be "just and reasonable" and not unduly discriminatory. This statute also permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariffs charged by us ultimately will be upheld if challenged, management believes that the tariffs now in effect for our pipelines are in compliance with the rates allowed under current FERC guidelines.
We have been approved by the FERC to charge market-based rates in most of the refined products locations served by our pipeline systems. In those locations where market-based rates have been approved, we are able to establish rates that are based upon competitive market conditions.
Intrastate Regulation
Some of our pipeline operations are subject to regulation by the Railroad Commission of Texas ("Texas RRC"), the Pennsylvania Public Utility Commission ("PA PUC") and other state regulatory agencies, as applicable. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.


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Title to Properties
Substantially all of our pipelines were constructed on rights-of-way granted by the apparent record owners of the property and, in limited instances, these rights-of-way are revocable at the election of the grantor. Several rights-of-way for the pipelines and other real property assets are shared with other pipelines and other assets owned by affiliates of Sunoco and by third parties. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for the common carrier pipelines. The previous owners of the applicable pipelines may not have commenced or concluded eminent domain proceedings for some rights-of-way.
Some of the leases, easements, rights-of-way, permits, and licenses acquired by us or transferred to us upon the closing of the IPO require the consent of the grantor to transfer these rights, which in some instances is a governmental entity. We have obtained or are in the process of obtaining third-party consents, permits, and authorizations sufficient for the transfer of the assets necessary to operate the business in all material respects. In our opinion, with respect to any consents, permits, or authorizations that have not been obtained, the failure to obtain them will not have a material adverse effect on the operation of our business.
We have satisfactory title to substantially all of the assets contributed in connection with the IPO. Although titles to these properties are subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens for environmental contamination, taxes and other burdens, easements, or other restrictions, management believes that none of these burdens materially detract from the value of the properties or will materially interfere with their use in the operation of our business.
Employees
We have no employees. To carry out the operations of Sunoco Logistics Partners L.P., our general partner and its affiliates employed approximately 2,575 people at December 31, 2016 who provide direct support to the operations. Labor unions or associations represented approximately 1,220 of these employees at December 31, 2016.
(d) Financial Information about Geographical Areas
We do not have significant amounts of revenue or segment profit or loss attributable to international activities.
(e) Available Information
We make available, free of charge on our website, www.sunocologistics.com, periodic reports that we file with the Securities Exchange Commission ("SEC"), including our annual report on Form 10-K, quarterly reports on Form 10-Q and amendments to those reports, as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC.

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ITEM 1A.
RISK FACTORS
We believe that the following risk factors address the known material risks related to our business, partnership structure and debt obligations, as well as the material tax risks to our common unitholders. If any of the following risks were to actually occur, our business, results of operations, financial condition and cash flows, as well as any related benefits of owning our securities, could be materially and adversely affected.
Energy Transfer Partners, L.P. ("ETP") is the controlling member of our general partner interest and receives all of our incentive distribution rights. Additionally, ETP owns 67.1 million common units and 9.4 million Class B units, which represents a 23.0 percent limited partner ownership interest in the Partnership. We are a consolidated subsidiary of ETP.
The risk factor information presented below reflects the impacts of these transactions, including the change in the general partner ownership, and the ongoing business implications.
RISKS RELATED TO OUR BUSINESS
If we are unable to generate sufficient cash flow, our ability to pay quarterly distributions to our common unitholders at current levels or to increase our quarterly distributions in the future, could be materially impaired.
Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and credit facilities, and not solely on profitability, which is affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income. Our ability to generate sufficient cash from operations is largely dependent on our ability to successfully manage our businesses which may also be affected by economic, financial, competitive, and regulatory factors that are beyond our control. To the extent we do not have adequate cash reserves, our ability to pay quarterly distributions to our common unitholders at current levels could be materially impaired.
An increase in interest rates may cause the market price of our units to decline.
Like all equity investments, an investment in our units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other investment opportunities may cause the trading price of our units to decline.
A material decrease in demand driven by unfavorable crude oil prices could materially and adversely affect our results of operations, financial position or cash flows.
The volume of crude oil transported through our integrated pipelines, terminal facilities and acquisition and marketing assets depends on the availability of attractively priced crude oil produced or received in the areas served by our assets. A period of sustained crude oil price declines, as experienced in 2014 and 2015, could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to our customers, could materially reduce demand for crude oil in the these areas. In either case, the volumes of crude oil transported through our pipelines, terminal facilities and acquisition and marketing assets could decline, and it could likely be difficult to secure alternative sources of attractively priced crude supply in a timely fashion or at all. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position or cash flows could be materially and adversely affected.
A material decrease in demand resulting from unfavorable natural gas liquids ("NGLs") prices could materially and adversely affect our results of operations, financial position, or cash flows.
Any significant and prolonged change in the actual or expected demand for NGLs could have an adverse impact on the volumes transported through our pipelines and/or terminals, or bought and sold through our acquisition and marketing assets. Changes in demand could result from additional regulatory restrictions on the extraction of NGLs that would significantly increase the cost of extraction and procurement; changes in technology affecting the mix of energy products available; or changes in laws, regulations, or costs related to exportation. Any material decrease in demand could have a material adverse effect on our results of operations, financial position, or cash flows.


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A sustained decrease in demand for refined products in the markets served by our pipelines and terminals could materially and adversely affect our results of operations, financial position, or cash flows.
The following are material factors that could lead to a sustained decrease in market demand for refined products:
a sustained recession or other adverse economic conditions that result in lower purchases of refined petroleum products;
higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions, or other factors;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;
a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and
a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.
Any reduction in throughput capacity available to our shippers, including our crude oil, NGLs and refined products acquisition and marketing businesses, on either our pipelines or interconnecting third-party pipelines could cause a reduction of volumes transported through our pipelines and our terminals.
Users of our pipelines and terminals are dependent upon our pipelines, as well as connections to third-party pipelines, to receive and deliver crude oil, NGLs and refined products. Any interruptions or reduction in the capabilities of our pipelines or these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes would result in reduced volumes transported through our pipelines or our terminals. If additional shippers begin transporting volume over interconnecting pipelines, the allocations to our existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported through our pipelines or our terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on our results of operations, financial position, or cash flows.
Similarly, our crude oil, NGLs and refined products acquisition and marketing businesses are dependent upon our pipelines and third-party pipelines to transport their products. Any material interruptions or allocations that affect the ability of those businesses to transport products, or the cost of such transportation, could have a material adverse effect on our results of operations, financial position, or cash flows.
If we are unable to complete capital projects at their expected costs and/or in a timely manner, as a result of protests, legal actions and/or appeals which may cause construction delays, or if the market conditions assumed in our project economics deteriorate, our results of operations, financial condition, or cash flows could be affected materially and adversely.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Furthermore, protests, legal actions and/or appeals of regulatory decisions may cause delays in our projects resulting in cost increases and renegotiation of customer contracts for timing delays. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
changes in market conditions impacting long lead-time projects;
market-related increases in a project's debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.
Our forecasted operating results also are based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative supplies of crude oil, NGLs and refined products and overall customer demand.

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An impairment of goodwill and intangible assets could reduce our earnings.
At December 31, 2016, our consolidated balance sheet reflected $1.61 billion of goodwill and $977 million of intangible assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets, such as intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate non-cash charge to earnings with a correlative effect on partners' capital and balance sheet leverage as measured by debt to total capitalization.
For additional information on our goodwill impairment test, see Note 2 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."
Future acquisitions and expansions may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.
We evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or a substantial increase in indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly.
Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets, new geographic areas and the businesses associated with them. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined and we may experience unanticipated delays in realizing the benefits of an acquisition. In some cases, we have indemnified the previous owners and operators of acquired assets.
Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions. In addition, the terms of an acquisition may require us to assume certain prior known or unknown liabilities for which we may not be indemnified or have adequate insurance.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations, and those of our customers and suppliers, may be subject to operational hazards or unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, and other events beyond our control. If one or more of the facilities that we own, or any third-party facilities that we receive from or deliver to, are damaged by any disaster, accident, catastrophe or other event, our operations could be significantly interrupted. These interruptions might involve a loss of equipment or life, injury, extensive property damage, or maintenance and repair outages. The duration of the interruption will depend on the seriousness of the damages or required repairs. We may not be able to maintain or obtain insurance to cover these types of interruptions, or in coverage amounts desired, at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could materially and adversely affect our results of operations, financial position, or cash flows.
We are exposed to the credit and other counterparty risk of our customers in the ordinary course of our business.
We have various credit terms with virtually all of our customers, and our customers have varying degrees of creditworthiness. Although we evaluate the creditworthiness of each of our customers, we may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose us to an increased risk of nonpayment or other default under our contracts and other arrangements with them. In the event that a material customer or customers default on their payment obligations to us, this could materially and adversely affect our results of operations, financial position, or cash flows.
Mergers among our customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced marketing margins and/or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

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Rate regulation or market conditions may not allow us to recover the full amount of increases in our costs. Additionally, a successful challenge to our rates could materially and adversely affect our results of operations, financial position, or cash flows.
The primary rate-making methodology of the Federal Energy Regulatory Commission ("FERC") is price indexing. We use this methodology in many of our interstate markets. In an order issued in December 2010, the FERC announced that, effective July 1, 2011, the index would equal the change in the producer price index for finished goods plus 2.65 percent (previously, the index was equal to the change in the producer price index for finished goods plus 1.3 percent). This index was in effect through June 2016. In an order issued December 2015, the FERC announced that, effective July 1, 2016, the index would equal the change in the producer price index for finished goods plus 1.23 percent. This index is to be effective through June 2021. If the changes in the index result in a rate reduction or are not large enough to fully reflect actual increases to our costs, our financial condition could be adversely affected. If the index results in a rate increase that is substantially in excess of the pipeline's actual cost increases, or it results in a rate decrease that is substantially less than the pipeline's actual cost decrease, the rates may be protested, and, if successful, result in the lowering of the pipeline's rates. 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.
Under the Energy Policy Act of 1992, certain interstate pipeline rates were deemed just and reasonable or "grandfathered." On our FERC-regulated pipelines, most of our revenues are derived from such grandfathered rates. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review. There is a risk that some rates could be found to be in excess of levels justified by our cost of service. In such event, the FERC would order us to reduce rates prospectively and could order us to pay reparations to shippers. Reparations could be required for a period of up to two years prior to the date of filing the complaint in the case of rates that are not grandfathered and for the period starting with the filing of the complaint in the case of grandfathered rates.
In addition, a state commission could also investigate our intrastate rates or terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates.
Potential changes to current rate-making methods and procedures may impact the federal and state regulations under which we will operate in the future. In addition, if the FERC's petroleum pipeline rate-making methodology changes, the new methodology could materially and adversely affect our results of operations, financial position, or cash flows.
Our operations are subject to federal, state, and local laws and regulations relating to environmental protection and operational safety that could require substantial expenditures.
Our pipelines, gathering systems and terminal operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of crude oil, NGLs and refined products result in a risk that crude oil, NGLs and refined products, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resource damages, personal injury, or property damage to private parties, and significant business interruption. We own or lease a number of properties that have been used to store or distribute crude oil, NGLs and refined products for many years. Many of these properties also have been previously owned or operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes were not under our control, and for which, in some cases, we have indemnified the previous owners and operators.
Our pipeline operations are subject to regulation by the Department of Transportation ("DOT"), under the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), pursuant to which PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of Pipeline Safety, has promulgated rules requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as "high consequence areas." Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
In addition, we are subject to a number of federal and state laws and regulations, including Occupational Safety and Health Administration, ("OSHA") and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and

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comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns or wells. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt.
Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. We may be unable to recover these costs through increased revenues.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, the operations of our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for our services.
The U.S. Senate has considered legislation to restrict U.S. emissions of carbon dioxide and other greenhouse gases ("GHG") that may contribute to global warming and climate change. Many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce GHG emissions. The U.S. House of Representatives has previously approved legislation to establish a "cap-and-trade" program, whereby the U.S. Environmental Protection Agency ("EPA") would issue a capped and steadily declining number of tradable emissions allowances to certain major GHG emission sources so they could continue to emit GHGs into the atmosphere. The cost of such allowances would be expected to escalate significantly over time, making the combustion of carbon-based fuels (e.g., refined petroleum products, oil and natural gas) increasingly expensive. Beginning in 2011, EPA regulations required specified large domestic GHG sources to report emissions above a certain threshold occurring after January 1, 2010. Our facilities are not subject to this reporting requirement since our GHG emissions are below the applicable threshold. In addition, the EPA has proposed new regulations, under the federal Clean Air Act, that would require a reduction in GHG emissions from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. It is not possible at this time to predict how pending legislation or new regulations to address GHG emissions would impact our business. However, the adoption and implementation of federal, state, or local laws or regulations limiting GHG emissions in the U.S. could adversely affect the demand for our crude oil, NGLs or refined products transportation and storage services, and result in increased compliance costs, reduced volumes or additional operating restrictions.
Terrorist attacks aimed at our facilities could adversely affect our business.
The U.S. government has issued warnings that energy assets, specifically the nation's pipeline and terminal infrastructure, may be the future targets of terrorist organizations. Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, refineries, or terminals could materially and adversely affect our results of operations, financial position, or cash flows.



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Our risk management policies cannot eliminate all commodity risk, and our use of hedging arrangements could result in financial losses or reduce our income. In addition, any non-compliance with our risk management policies could result in significant financial losses.
We follow risk management practices designed to minimize commodity risk, and engage in hedging arrangements to reduce our exposure to fluctuations in the prices of certain products we market. These hedging arrangements expose us to risk of financial loss in some circumstances, including when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for such products.
We have adopted risk management policies designed to manage risks associated with our businesses. However, these policies cannot eliminate all price-related risks, and there is also the risk of non-compliance with such policies. We cannot make any assurances that we will detect and prevent all violations of our risk management practices and policies, particularly if deception or other intentional misconduct is involved. Any violations of our risk management practices or policies by our employees or agents could result in significant financial losses.
We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which subjects us to the possibility of increased costs to retain necessary land use which could disrupt our operations.
We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew rights-of-way contracts on acceptable terms, or increased costs to renew such rights could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.
Whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline (e.g., common carrier), type of products shipped on the pipeline and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.
Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our results of operations and cash flows.
A portion of our general and administrative services have been outsourced to outside service providers. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.
We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of our security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability for us, lead to reputational damage, increase our compliance costs, or otherwise harm our business.
Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

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Our operations could be disrupted if our information systems fail, causing increased expenses and/or loss of sales.
Our business is highly dependent on financial, accounting and other, data processing systems and other communications and information systems. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.
Our business could be affected adversely by union disputes and strikes or work stoppages by our unionized employees.
As of December 31, 2016, approximately 47 percent of our workforce was covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppages could have a material adverse effect on our business, financial position, results of operations or cash flows.
We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.
Certain of our joint ventures have their own governing boards, and we may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in our or the joint venture's best interests. Likewise, we may be unable to prevent actions of the joint venture.





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RISKS RELATED TO OUR PARTNERSHIP STRUCTURE
Our general partner's discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement provides that our general partner may reduce our operating surplus by establishing cash reserves to provide funds for our future operating expenditures. In addition, the partnership agreement provides that our general partner may 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 our unitholders in any one or more of the next four quarters. These cash reserves will affect the amount of cash available for current distribution to our unitholders.
Even if unitholders are dissatisfied, they have limited rights under the partnership agreement to remove our general partner without its consent, which could lower the trading price of the common units.
The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management. 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. Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by ETP, the controlling member of our general partner. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a control premium in the trading price.
Our general partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuant to our partnership agreement, our general partner has the ability, in its sole discretion and without the approval of the unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our general partner, including:
the right to share in the Partnership's profits and losses;
the right to share in the Partnership's distributions;
the rights upon dissolution and liquidation of the Partnership;
whether, and the terms upon which, the Partnership may redeem the securities;
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Please see "We may issue additional common units without unitholder approval, which would dilute our unitholders' ownership interests." below.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner has the right to 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 the owner of our general partner from transferring its ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of the general partner with its own appointees.



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Conflicts of interest may arise between us and ETP as they are the controlling owner of our general partner, which, due to limited fiduciary responsibilities, may permit ETP and its affiliates to favor their own interests to the detriment of our unitholders.
ETP is the controlling owner of our general partner interest and owns 23.0 percent of our limited partnership interests, including ownership of our outstanding Class B units. Conflicts may arise between the interests of ETP and its affiliates (including our general partner), and our interests and those of our unitholders. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates (including ETP) over the interests of our unitholders. Our partnership agreement provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is "fair and reasonable" to us will be deemed approved by all partners, including the unitholders, and will not constitute a breach of the partnership agreement These conflicts may include, among others, the following situations:
ETP and its affiliates may engage in competition with us. Neither our partnership agreement nor any other agreement requires ETP to pursue a business strategy that favors us or utilizes our assets, and our general partner may consider the interests of parties other than us, such as ETP, in resolving conflicts of interest;
under our partnership agreement, our general partner's fiduciary duties are restricted, and our unitholders have only limited remedies available in the event of conduct constituting a potential breach of fiduciary duty by our general partner;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash available for distribution to our unitholders and the amount received by our general partner in respect of its incentive distribution rights ("IDRs");
our general partner determines which costs incurred by ETP and its affiliates are reimbursable by us; and
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any additional contractual arrangements are fair and reasonable to us; and our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.
We are a holding company. We conduct our operations through our subsidiaries and depend on cash flow from our subsidiaries to pay distributions to our unitholders and service our debt obligations.
We are a holding company. We conduct our operations through our subsidiaries. As a result, our cash flow and ability to pay distributions to our unitholders and to service our debt is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory or contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our unitholders or pay interest or principal on our debt securities when due.
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.
ETP is the controlling owner of our general partner and also owns 23.0 percent of our limited partnership interests, including our outstanding Class B units, and all of our IDRs. Our general partner may cause us to borrow funds from affiliates of ETP or from third parties in order to pay cash distributions to our unitholders and to our general partner, including distributions with respect to our general partner's IDRs.
Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price, may not receive a return on the investment, and may incur a tax liability upon the sale.


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We may issue additional common units without unitholder approval, which would dilute our unitholders' ownership interests.
We may issue an unlimited number of common units or other limited partner interests, including limited partner interests that rank senior to our common units, without the approval of our unitholders. The issuance of additional common units, or other equity securities of equal or senior rank, will decrease the proportionate ownership interest of existing unitholders and reduce the amount of cash available for distribution to our common unitholders and may adversely affect the market price of our common units.
A unitholder may not have limited liability if a state or federal court finds that we are not in compliance with the applicable statutes or that unitholder action constitutes control of our business.
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 states. A unitholder could be held liable in some circumstances for our obligations to the same extent as a general partner if a state or federal court determined that:
we had been conducting business in any state without complying with the applicable limited partnership statute; or
the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted participation in the "control" of our business.
Under applicable state law, our general partner has unlimited liability for our obligations, including our debts and environmental liabilities, if any, except for our contractual obligations that are expressly made without recourse to our general partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.






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RISKS RELATED TO OUR DEBT
References under this heading to "we," "us," and "our" mean Sunoco Logistics Partners Operations L.P.
We may not be able to obtain funding, or obtain funding on acceptable terms, to meet our future capital needs.
Global market and economic conditions have been, and continue to be, volatile. The debt and equity capital markets have been impacted by, among other things, significant write-offs in the financial services sector and the re-pricing of credit risk in the broadly syndicated market.
As a result, the cost of raising money in the debt and equity capital markets could be higher and the availability of funds from those markets could be diminished if we seek access to those markets. Accordingly, we cannot be certain that additional funding will be available, if needed and to the extent required, on acceptable terms. If additional funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.
Restrictions in our debt agreements may prevent us from engaging in some beneficial transactions or paying distributions to unitholders.
As of December 31, 2016, our total outstanding indebtedness was $7.27 billion, excluding net unamortized fair value adjustments, bond discounts and debt issuance costs. Our payment of principal and interest on the debt will reduce the cash available for distribution on our units, as will our obligation to repurchase the senior notes upon the occurrence of specified events involving a change in control of our general partner. In addition, we are prohibited by our credit facilities and the senior notes from making cash distributions during an event of default, or if the payment of a distribution would cause an event of default under any of our debt agreements. Our leverage and various limitations in our credit facilities and senior notes may reduce our ability to incur additional debt, engage in some transactions, and capitalize on acquisition or other business opportunities. Any subsequent refinancing of our current debt or any new debt could have similar or greater restrictions.
We could incur a substantial amount of debt in the future, which could prevent us from fulfilling our debt obligations.
We are permitted to incur additional debt, subject to certain limitations under our revolving credit facilities and, in the case of secured debt, under the indenture governing the notes. If we incur additional debt in the future, our increased leverage could, for example:
make it more difficult for us to satisfy our obligations under our debt securities or other indebtedness and, if we fail to comply with the requirements of the other indebtedness, could result in an event of default under our debt securities or such other indebtedness;
require us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow from working capital, capital expenditures and other general corporate activities;
limit our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;
limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
detract from our ability to successfully withstand a downturn in our business or the economy, generally; and
place us at a competitive disadvantage against less leveraged competitors.
Our notes and related guarantees are effectively subordinated to any secured debt of ours or the guarantor, as well as to any debt of our non-guarantor subsidiaries, and, in the event of our bankruptcy or liquidation, holders of our notes will be paid from any assets remaining after payments to any holders of our secured debt.
Our notes and related guarantees are general unsecured senior obligations of us and the guarantor, respectively, and effectively subordinated to any secured debt that we or the guarantor may have to the extent of the value of the assets securing that debt. The indentures permit the guarantor and us to incur secured debt provided certain conditions are met. Our notes are effectively subordinated to the liabilities of any of our subsidiaries unless such subsidiaries guarantee such notes in the future.
If we are declared bankrupt or insolvent, or are liquidated, the holders of our secured debt will be entitled to be paid from our assets securing their debt before any payment may be made with respect to our notes. If any of the preceding events occur, we may not have sufficient assets to pay amounts due on our secured debt and our notes.

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We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Our partnership agreement requires us to distribute 100 percent of our available cash to our general partner and Sunoco Logistics Partners L.P. within 45 days following the end of every quarter. The Sunoco Logistics Partners L.P. partnership agreement requires it to distribute 100 percent of its available cash to its unitholders of record within 45 days following the end of every quarter. Available cash with respect to any quarter is generally all of our or Sunoco Logistics Partners L.P.'s, as applicable, cash on hand at the end of such quarter, less cash reserves for certain purposes. The controlling owner of our general partner and the board of directors of Sunoco Logistics Partners L.P.'s general partner will determine the amount and timing of such distributions and have broad discretion to establish and make additions to our or Sunoco Logistics Partners L.P.'s reserves, as applicable, or the reserves of our or Sunoco Logistics Partners L.P.'s operating subsidiaries, as applicable, as they determine are necessary or appropriate. As a result, we and Sunoco Logistics Partners L.P. do not have the same flexibility as corporations or other entities that do not pay dividends or that have complete flexibility regarding the amounts they will distribute to their equity holders. Although our payment obligations to our partners are subordinate to our payment obligations on our debt, the timing and amount of our quarterly distributions to our partners could significantly reduce the cash available to pay the principal, premium (if any), and interest on our notes.
Rising short-term interest rates could increase our financing costs and reduce the amount of cash we generate.
As of December 31, 2016, we had $1.9 billion of floating-rate debt outstanding. Rising short-term rates could materially and adversely affect our results of operations, financial condition or cash flows.
Any reduction in our credit ratings or in ETP's credit ratings could materially and adversely affect our business, results of operations, financial condition and liquidity.
We currently maintain an investment-grade rating by Moody's, S&P and Fitch Ratings. However, our current ratings may not remain in effect for any given period of time and a rating may be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. If Moody's, S&P or Fitch Ratings were to downgrade our long-term rating, particularly below investment grade, our borrowing costs could significantly increase, which would adversely affect our financial results, and our potential pool of investors and funding sources could decrease. Further, due to our relationship with ETP, any downgrade in ETP's credit ratings could also result in a downgrade in our credit ratings. Ratings from credit agencies are not recommendations to buy, sell or hold our securities, and each rating should be evaluated independently of any other rating.






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TAX RISKS TO OUR COMMON UNITHOLDERS
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service ("IRS") treats us as a corporation or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.
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 matter. Despite the fact that we are a limited partnership under Pennsylvania law, we would be treated as a corporation for federal income tax purposes unless we satisfy a "qualifying income" requirement. We believe that we satisfy the qualifying income requirement based on our current operations. Failing to meet this requirement 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 at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Therefore, treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common units.
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. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.
On November 2, 2015, President Obama signed into law the Bipartisan Budget Act of 2015 (the "Act"). The Act includes significant changes to the rules governing the audits of entities that are treated as partnerships for U.S. federal income tax purposes. The new rules under the Act, which are effective for tax years beginning after December 31, 2017, repeal and replace the regimes under the current Tax Equity and Fiscal Responsibility Act ("TEFRA") audit provisions for partnerships. The Act allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. The Partnership does not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.
Under the new streamlined audit procedures, a partnership would be responsible for paying the imputed underpayment of tax resulting from the audit adjustments in the adjustment year even though partnerships are "pass-through entities." However, as an alternative to paying the imputed underpayment of tax at the partnership level, a partnership may elect to provide the audit adjustment information to the reviewed year partners, whom in turn would be responsible for paying the imputed underpayment of tax in the adjustment year. The Partnership anticipates that it would elect to push any imputed underpayments resulting from future audit adjustments to its reviewed year partners in accordance with the procedures set forth in the final Treasury Regulations promulgated under the new rules when such Treasury Regulations are provided.
Should a partnership not elect to pass the audit adjustments on to its partners, the partnerships imputed underpayment generally would be determined at the highest rate of tax in effect for the reviewed year. Currently, the highest rate of tax would be 39.6 percent for individual taxpayers. However, the Act authorizes the Treasury to establish procedures whereby the imputed underpayment amount may be modified to more accurately reflect the amount owed, if the partnership can substantiate a lower tax rate or demonstrate a portion of the imputed underpayment amount is allocable to a partner that would not owe tax (a tax exempt entity) or a partner has already paid the tax. It is not yet clear how state and local tax authorities will respond to the new regime. The Partnership is closely monitoring the development and issuance of regulations or other additional guidance under the new partnership audit regime.
The sale or exchange of 50 percent or more of our capital and profit interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.
Our partnership will be considered to have been terminated for tax purposes when there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period (a "technical termination"). For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will be counted only once. A sale or exchange would occur, for example, if we sold our business or merged with another company, or if any of our unitholders, including ETP and its affiliates, sold or transferred their partnership interests in us. Our termination would, among other things, result in the closing of our taxable year for all of our unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of

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depreciation deductions allowable in computing our taxable income. Our termination would not affect our classification as a partnership for federal income tax purposes. Instead, we would be treated as a new partnership for federal income tax purposes, in which case we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
As a result of ETP's acquisition of the Partnership in October 2012, the 50 percent threshold described above was exceeded. Our classification as a partnership was not affected, but instead, we were treated as a new partnership for federal income tax purposes. The technical termination resulted in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may have resulted in more than twelve months of our taxable income or loss being included in the unitholder's taxable income for the year of termination. As a result of the technical termination, we were required to file two tax returns for the calendar year 2012. We were required to make new tax elections after the technical termination, including a new election under Section 754 of the Internal Revenue Code, and the termination resulted in a deferral of our deductions for depreciation. A termination could also result in penalties if we had been unable to determine that the termination had occurred. Moreover, the technical termination could accelerate the application of, or subject us to, any tax legislation enacted before the technical termination. The IRS has recently announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the calendar year notwithstanding two partnership tax years. We were successful in petitioning the IRS for this technical termination relief.
Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive 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 result from that income.
Tax gain or loss on disposition of our limited partner units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they 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 that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as 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 individual retirement accounts 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 U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or non-U.S. person, you should consult your tax advisor before investing in our common units.





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Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our limited partner units.
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 do business or own property, 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. We currently conduct our business and own assets in 37 states, most of which impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders' responsibility to file all United States federal, state and local tax returns.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected and the costs of any such contest will reduce cash available for distributions 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. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our unitholders.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, some of our operations are currently conducted through subsidiaries that are organized as corporations for U.S. federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.





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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 result in a unitholder owing more tax and may adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will 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 to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes which own units in us, a successful IRS challenge could result in this subsidiary having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our unitholders.
We prorate our items of income, gain, loss and deduction 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller") to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for 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 there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our public unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. 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 current valuation methods, subsequent purchasers of our 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 Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of 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 also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

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RISKS RELATED TO THE ENERGY TRANSFER PARTNERS MERGER
The following risk factors relate to the previously announced merger with ETP (the "Merger"). For more information on the Merger, please read the registration statement and related information on the Merger that we have filed with the SEC.     
We or ETP may have difficulty attracting, motivating and retaining executives and other employees in light of the Merger.
Uncertainty about the effect of the Merger on us or ETP employees may have an adverse effect on the combined organization. This uncertainty may impair these companies' ability to attract, retain and motivate personnel until the Merger is completed. Employee retention may be particularly challenging during the pendency of the Merger, as employees may feel uncertain about their future roles with the combined organization. In addition, we or ETP may have to provide additional compensation in order to retain employees. If employees of us or ETP depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined organization, the combined organization's ability to realize the anticipated benefits of the Merger could be adversely affected.
We and ETP are subject to business uncertainties and contractual restrictions while the proposed Merger is pending, which could adversely affect each party's business and operations.
In connection with the pending Merger, it is possible that some customers, suppliers and other persons with whom we or ETP have business relationships may delay or defer certain business decisions, or might decide to seek to terminate, change or renegotiate their relationship with us or ETP as a result of the Merger, which could negatively affect our and ETP's respective revenues, earnings and cash available for distribution, as well as the market price of our respective common units, regardless of whether the Merger is completed.
Under the terms of the merger agreement, we and ETP are each subject to certain restrictions on the conduct of its business prior to completing the Merger, which may adversely affect its ability to execute certain of its business strategies. Such limitations could negatively affect each party's businesses and operations prior to the completion of the Merger. Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on each party.
We and ETP will incur substantial transaction-related costs in connection with the Merger.
We and ETP expect to incur a number of non-recurring transaction-related costs associated with completing the Merger, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our and ETP's businesses. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.
Failure to successfully combine our and ETP's businesses in the expected time frame may adversely affect the future results of the combined organization, and, consequently, the value of our common units.
The success of the proposed merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our and ETP's businesses. To realize these anticipated benefits, the businesses must be successfully combined. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the Merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the Merger. These integration difficulties could result in declines in the market value of our common units.





36



The Merger is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of our common units and the future business and financial results of us and ETP.
The completion of the Merger is subject to a number of conditions. The completion of the Merger is not assured and is subject to risks, including the risk that approval of the Merger by ETP's common unitholders or by governmental agencies is not obtained or that other closing conditions are not satisfied. If the Merger is not completed, or if there are significant delays in completing the Merger, the trading price of our common units and the respective future business and financial results of us and ETP could be negatively affected, and each of them will be subject to several risks, including the following:
the parties may be liable for damages to one another under the terms and conditions of the merger agreement;
negative reactions from the financial markets, including declines in the price of our common units due to the fact that current prices may reflect a market assumption that the Merger will be completed; and
the attention of our and ETP's management will have been diverted to the Merger rather than each organization's own operations and pursuit of other opportunities that could have been beneficial to that organization.
If a governmental authority asserts objections to the Merger, we and ETP may be unable to complete the Merger or, in order to do so, we and ETP may be required to comply with material restrictions or satisfy material conditions.
The closing of the Merger is subject to the condition that there is no law, injunction, judgment or ruling by a governmental authority in effect enjoining, restraining, preventing or prohibiting the Merger contemplated by the merger agreement. If a governmental authority asserts objections to the Merger, we or ETP may be required to divest assets or accept other remedies in order to complete the Merger. There can be no assurance as to the cost, scope or impact of the actions that may be required to address any governmental authority objections to the Merger. If we or ETP takes such actions, it could be detrimental to us or to the combined organization following the consummation of the Merger. Furthermore, these actions could have the effect of delaying or preventing completion of the proposed merger or imposing additional costs on or limiting the revenues or cash available for distribution of the combined organization following the consummation of the Merger.
Additionally, state attorneys general could seek to block or challenge the Merger as they deem necessary or desirable in the public interest at any time, including after completion of the transaction. In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
ETP's and our financial estimates are based on various assumptions that may not prove to be correct.
The financial estimates set forth in the forecast included in the SEC filings relating to the Merger and provided to the ETP Board and our Board, as applicable, and the ETP Conflicts Committee and our Conflicts Committee, as applicable, and their respective financial advisors are based on assumptions of, and information available to, ETP and us at the time they were prepared. Neither ETP nor we know whether such assumptions will prove correct. Any or all of such estimates may turn out to be wrong. Such estimates can be adversely affected by inaccurate assumptions or by known or unknown risks and uncertainties, many of which are beyond ETP's and our control. Many factors, including the risks outlined in this "Risk Factors" section, will be important in determining ETP's and our future results. As a result of these contingencies, actual future results may vary materially from ETP's and our estimates.
ETP's and our financial estimates were not prepared with a view toward public disclosure, and such financial estimates were not prepared with a view toward compliance with published guidelines of any regulatory or professional body. Further, any forward-looking statement speaks only as of the date on which it is made, and ETP and we undertake no obligation, other than as required by applicable law, to update our respective financial estimates herein to reflect events or circumstances after the date those financial estimates were prepared or to reflect the occurrence of anticipated or unanticipated events or circumstances.
The financial estimates were prepared by, and are the responsibility of, ETP and us alone. Moreover, neither ETP's nor our independent accountants, Grant Thornton LLP, nor any other independent accountants, have compiled, examined or performed any procedures with respect to ETP's or our prospective financial information, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and, accordingly, Grant Thornton LLP assumes no responsibility for, and disclaims any association with, ETP's or our prospective financial information. The reports of Grant Thornton LLP relate exclusively to the historical financial information of the entities named in those reports and do not cover any other information and should not be read to do so.


37



The number of our outstanding common units will increase as a result of the Merger, which could make it more difficult for us to pay the current level of quarterly distributions.
As of February 22, 2017, we had more than 322 million common units outstanding. We will issue approximately 827 million common units in connection with the Merger. Accordingly, the aggregate dollar amount required to pay the current per unit quarterly distribution on all of our common units will increase, which could increase the likelihood that we will not have sufficient funds to pay the current level of quarterly distributions to all of our unitholders. Using a $0.52 per common unit distribution (the amount we paid with respect to the fourth fiscal quarter of 2016 on February 14, 2017 to holders of record as of February 7, 2017), the aggregate cash distribution paid to our unitholders totaled $272 million, including a distribution of $105 million to our general partner in respect of its general partner interest and ownership of incentive distribution rights. Using the same $0.52 per common unit distribution, the combined pro forma distribution with respect to the fourth fiscal quarter of 2016, had the Merger been completed prior to such distribution, would have resulted in total cash distributions of approximately $796 million, including a distribution of $233 million to our general partner in respect of its general partner interest and incentive distribution rights.
A downgrade in our or our subsidiaries' credit ratings following the Merger could impact the combined entity's access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
Following the Merger, we will be a more leveraged entity on a consolidated basis than we are prior to the Merger, and the Merger may cause rating agencies to reevaluate our and our subsidiaries' ratings. A downgrade of our or our subsidiaries' credit ratings might increase our and our subsidiaries' cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. We and our subsidiaries' ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
No ruling has been obtained with respect to the U.S. federal income tax consequences of the Merger.
No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax consequences of the Merger. Instead, we and ETP are relying on the opinions of our respective counsel as to the U.S. federal income tax consequences of the Merger, and such counsel's conclusions may not be sustained if challenged by the IRS. If either we or ETP were to be treated as a corporation for U.S. federal income tax purposes, the consequences of the Merger would be materially different.
Our common unitholders could recognize taxable income or gain for U.S. federal income tax purposes as a result of the Merger.
Although for state law purposes ETP will become our wholly-owned subsidiary as a result of the Merger, for U.S. federal income tax purposes, ETP (rather than us) will be treated as the continuing partnership following the Merger. As a result, for U.S. federal income tax purposes, we will be deemed to contribute all of our assets to ETP in exchange for ETP units and the assumption of our liabilities, followed by a liquidation of us in which ETP units are distributed to our unitholders. In addition, as a result of the Merger, our unitholders will become limited partners of ETP for U.S. federal income tax purposes and will be allocated a share of ETP's nonrecourse liabilities. None of our common unitholders should recognize any income, gain or loss, for U.S. federal income tax purposes as a result of the Merger other than any gain recognized as a result of (1) decreases in partnership liabilities pursuant to Section 752 of the Code and (2) a disguised sale attributable to contributions of cash or other property to us after the date of the merger agreement and prior to the effective time of the Merger. Each of our common unitholder's share of our nonrecourse liabilities will be recalculated following the Merger. Any resulting increase or decrease in a common unitholder's nonrecourse liabilities will result in a corresponding increase or decrease in such unitholder's adjusted tax basis in its common units. A reduction in a common unitholder's share of nonrecourse liabilities would, if such reduction exceeds the unitholder's tax basis in his or her common units, under certain circumstances, result in the recognition of taxable gain by a common unitholder. While there can be no assurance, we do not expect any common unitholders to recognize gain in this manner.



38



Tax Risks Related to Owning Common Units in SXL Following the Merger
For U.S. federal income tax purposes, the merger is intended to be a "merger" of SXL and ETP within the meaning of Treasury Regulations promulgated under Section 708 of the Code. Assuming the merger is treated as such, although for state law purposes ETP will become a wholly owned subsidiary of SXL in the merger, for U.S. federal income tax purposes, ETP (rather than SXL) will be treated as the continuing partnership following the merger and SXL will be treated as the terminated partnership. As a result, each holder of SXL common units, including SXL common unitholders and the ETP common unitholders that will receive SXL common units in the merger, will be treated as a partner of ETP for U.S. federal income tax purposes following the merger.
Following the merger, in addition to the risks described above, deemed holders of ETP common units, for U.S. federal income tax purposes, will continue to be subject to the risks that holders of ETP common units are currently subject to, which are described in ETP's Annual Report on Form 10-K for the fiscal year ended December 31, 2015 as updated by any subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, all of which are filed with the SEC and incorporated by reference into this proxy statement/prospectus. See "Where You Can Find More Information" for the location of information incorporated by reference in this proxy statement/prospectus.


39



ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
 
ITEM 2.
PROPERTIES
See Item 1. (c) for a description of the locations and general character of our material properties.
 

40




ITEM 3.
LEGAL PROCEEDINGS
There are certain legal and administrative proceedings arising prior to the February 2002 initial public offering ("IPO") pending against our Sunoco-affiliated predecessors and us (as successor to certain liabilities of those predecessors). Although the ultimate outcome of these proceedings cannot be ascertained at this time, it is reasonably possible that some of them may be resolved unfavorably. Sunoco, Inc. ("Sunoco") has agreed to indemnify us for 100 percent of all losses from environmental liabilities related to the transferred assets arising prior to, and asserted within 21 years of February 8, 2002. There is no monetary cap on this indemnification from Sunoco. Sunoco's share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the February 8, 2002 date. Any remediation liabilities not covered by this indemnity will be our responsibility. In addition, Sunoco is obligated to indemnify us under certain other agreements executed after the IPO.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or cash flows. We are required to report environmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $0.1 million.
In January 2012, the Partnership experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the Pipeline Hazardous Material Safety Administration ("PHMSA") issued a Corrective Action Order under which the Partnership is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. The Partnership also entered into an Order on Consent with the Environmental Protection Agency ("EPA") regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. The Partnership has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, the Partnership received a proposed penalty of $2.0 million from the U.S. Department of Justice ("DOJ") associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, the Partnership does not expect there to be a material impact to its results of operations, cash flows or financial position.
In 2012, the EPA issued a proposed consent agreement related to the releases that occurred at the Partnership's pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the DOJ by the EPA. In November 2012, the Partnership received an initial assessment of $1.4 million associated with these releases. The Partnership is in discussions with the EPA and the DOJ on this matter to resolve the issue. The timing or outcome of this matter cannot be reasonably determined at this time. However, the Partnership does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2015 and October 2016, the PHMSA issued separate Notices of Probable Violation ("NOPVs") and a Proposed Compliance Order ("PCO") related to the Partnership's West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalties are in excess of $0.1 million, and the Partnership is currently in discussions with the PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of the Partnership's Permian Express 2 pipeline system in Texas. The correspondence proposes penalties in excess of $0.1 million, and the Partnership is currently in discussions with the PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In June 2016, the PHMSA issued NOPVs and a PCO in connection with alleged violations on the Partnership's Texas crude oil pipeline system. The proposed penalties are in excess of $0.1 million, and the Partnership is currently in discussions with the PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In July 2016, the PHMSA issued a NOPV and PCO in connection with inspection and maintenance activities related to a 2013 incident on the Partnership's crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $0.1 million, and the Partnership is currently in discussions with the PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.

41



Sunoco Logistics Merger Litigation
Between January 6, 2017 and February 8, 2017, seven purported ETP common unitholders ("Plaintiffs") separately filed seven putative unitholder class action lawsuits challenging the merger and the disclosures made in connection with the merger. The lawsuits are styled (a) Koma v. Energy Transfer Partners, L.P., et al., Case No. 3:17-cv-00060-G, in the United States District Court for the Northern District of Texas, Dallas Division (the "Koma Lawsuit"); (b) Ashraf v. Energy Transfer Partners, L.P. et al., Case No. 3:17-cv-00118-B, in the United States District Court for the Northern District of Texas, Dallas Division (the "Ashraf Lawsuit"); (c) Shure v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00044-UNA, in the United States District Court for the District of Delaware (the "Shure Lawsuit"); (d) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the "Verlin Lawsuit"); (e) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the "Duany Lawsuit"); (f) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the "Epstein Lawsuit") and (g) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the "Sgnilek Lawsuit" and collectively with the Koma Lawsuit, Ashraf Lawsuit, Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit, the "Lawsuits"). The Koma Lawsuit, Ashraf Lawsuit, Duany Lawsuit, and Epstein Lawsuit are filed against ETP, ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively "Defendants").
Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According to Plaintiffs, the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE's, ETP's, and Sunoco Logistics' financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, Plaintiffs allege that (i) Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP have aided and abetted those alleged breaches.
Based on these allegations, Plaintiffs seek to enjoin Defendants from proceeding with or consummating the merger unless and until Defendants disclose the allegedly omitted information summarized above. The Koma Lawsuit and Sgnilek Lawsuit also seek to enjoin Defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and attorneys' fees.
Defendants' dates to answer, move to dismiss, or otherwise respond to the Lawsuits have not yet been set. Defendants cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this annual report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. Defendants believe the Lawsuits are without merit and intend to defend vigorously against the Lawsuits and any other actions challenging the merger.


42




ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.


43



PART II
 
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES
Our common units are listed on the New York Stock Exchange under the symbol "SXL" beginning on February 5, 2002. At the close of business on February 22, 2017, there were 61 holders of record of our common units. These holders of record included the general partner with 67.1 million common units registered in its name, and Cede & Co., a clearing house for stock transactions, with the majority of the remaining 255.3 million common units registered to it. Additionally, 9.4 million Class B units were issued in October 2015, which represent a new class of limited partner interests in the Partnership. The Class B units are not entitled to receive quarterly distributions that are made on the Partnership's common units, but are otherwise entitled to share in earnings pro-rata with common units. As part of the anticipated merger with ETP, all SXL common and Class B units held by ETP will be retired.
Our registration statements to offer our limited partnership interests and debt securities to the public also allows our general partner to sell, in one or more offerings, any common units it owns. For each offering of our limited partnership units, including those owned by our general partner, we will provide a prospectus supplement that will contain specific information about the terms of that offering.
The high and low sales price ranges (composite transactions) and distributions declared (per unit), by quarter, for 2016 and 2015 were as follows:
 
 
2016
 
2015
 
 
Unit Price
 
Declared
Distributions
 
Unit Price
 
Declared
Distributions
Quarter
 
High
 
Low
 
High
 
Low
 
1st
 
$
28.72

 
$
15.43

 
$
0.4890

 
$
46.72

 
$
36.62

 
$
0.4190

2nd
 
$
29.77

 
$
22.63

 
$
0.5000

 
$
44.90

 
$
37.10

 
$
0.4380

3rd
 
$
31.49

 
$
26.88

 
$
0.5100

 
$
38.65

 
$
25.44

 
$
0.4580

4th
 
$
28.61

 
$
22.07

 
$
0.5200

 
$
32.89

 
$
21.41

 
$
0.4790

Within 45 days after the end of each quarter, we distribute all cash on hand at the end of the quarter, less reserves established by our general partner in its discretion. This is defined as "available cash" in the partnership agreement. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. We will make minimum quarterly distributions of $0.075 per common unit, to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
In connection with the acquisition from Vitol Inc., our general partner executed an amendment to our Third Amended and Restated Agreement of Limited Partnership in September 2016, which provides for a reduction to the incentive distributions to be paid to our general partner. The reductions will total $60 million over a two-year period, recognized ratably over eight quarters, and began with the third quarter 2016 cash distribution.
If cash distributions exceed $0.0833 per unit in a quarter, our general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as "incentive distributions." The amounts shown in the table under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to our unitholders if it would cause an event of default, or an event of default exists under the credit facilities or the senior notes (see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources").






44



The following table compares the target distribution levels and distribution "splits" between the general partner and the holders of our common units:
 
 
Total Quarterly
Distribution
Target Amount
 
Marginal
Percentage Interest in
Distributions
 
 
General Partner
 
Unitholders
Minimum Quarterly Distribution
 
$0.0750
 
1
%
 
 
99%
First Target Distribution
 
up to $0.0833
 
1
%
 
 
99%
Second Target Distribution
 
above $0.0833
 
 
 
 
 
 
up to $0.0958
 
14
%
(1) 
 
86%
Third Target Distribution
 
above $0.0958
 
 
 
 
 
 
up to $0.2638
 
36
%
(1) 
 
64%
Thereafter
 
above $0.2638
 
49
%
(1) 
 
51%
 (1)  
Includes general partner interest.


45




ITEM 6.
SELECTED FINANCIAL DATA
The following tables present selected current and historical financial data. The tables should be read together with the consolidated financial statements and the accompanying notes of Sunoco Logistics Partners L.P. included in Item 8. "Financial Statements and Supplementary Data." The tables also should be read together with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Due to the application of push-down accounting applied to our consolidated financial statements, in which our assets and liabilities were adjusted to fair value following the acquisition of our general partner by Energy Transfer Partners, L.P. ("ETP"), selected financial statements are presented using two different bases of accounting for the periods before and after the acquisition. The periods prior to the October 5, 2012 acquisition are identified as "Predecessor" and the periods from October 5, 2012 forward are identified as "Successor."
 
 
Successor
 
 
Predecessor
 
 
Year Ended December 31,
 
Period from Acquisition,
October 5, 2012 to
December 31, 2012
 
 
Period from
January 1, 2012 to
October 4, 2012
2016
 
2015
 
2014
 
2013
 
 
 
 
(in millions, except per unit data)
 
 
(in millions, except per unit data)
Income Statement Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
8,715

 
$
9,971

 
$
17,018

 
$
15,073

 
$
2,989

 
 
$
9,460

Affiliates
 
436

 
515

 
1,070

 
1,566

 
200

 
 
461

Gain on divestment and related matters
 

 

 

 

 

 
 
11

Total revenues
 
$
9,151

 
$
10,486

 
$
18,088

 
$
16,639

 
$
3,189

 
 
$
9,932

Operating income
 
$
815

 
$
530

 
$
367

 
$
560

 
$
159

 
 
$
460

Gain on investment in affiliate
 
$
41

 
$

 
$

 
$

 
$

 
 
$

Other income (1)
 
$
37

 
$
22

 
$
25

 
$
21

 
$
5

 
 
$
18

Income before income tax expense
 
$
736

 
$
418

 
$
325

 
$
504

 
$
150

 
 
$
413

Net Income
 
$
709

 
$
397

 
$
300

 
$
474

 
$
142

 
 
$
389

Net income attributable to noncontrolling interests
 
(3
)
 
(3
)
 
(9
)
 
(11
)
 
(3
)
 
 
(8
)
Net income attributable to redeemable noncontrolling interests
 
(1
)
 
(1
)
 

 

 

 
 

Net Income Attributable to Sunoco Logistics Partners L.P.
 
$
705

 
$
393

 
$
291

 
$
463

 
$
139

 
 
$
381

Net Income Attributable to Sunoco Logistics Partners L.P. per Limited Partner unit: (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
$
0.98

 
$
0.42

 
$
0.52

 
$
1.63

 
$
0.55

 
 
$
1.57

Diluted
 
$
0.98

 
$
0.42

 
$
0.51

 
$
1.63

 
$
0.55

 
 
$
1.57

Cash distributions per unit to Limited Partners: (2) (3)
 
 
 
 
 
 
 
 
 
 
 
 
 
Paid
 
$
1.98

 
$
1.72

 
$
1.43

 
$
1.17

 
$
0.26

 
 
$
0.66

Declared
 
$
2.02

 
$
1.79

 
$
1.50

 
$
1.23

 
$
0.27

 
 
$
0.71

Other Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (4)
 
$
1,233

 
$
1,153

 
$
971

 
$
871

 
$
219

 
 
$
591

Distributable Cash Flow (4)
 
$
943

 
$
874

 
$
756

 
$
664

 
$
165

 
 
$
444

(1) 
Includes equity income from our investments in the following joint ventures interests: Bakken Holdings Company LLC; Bayou Bridge Pipeline, LLC; Explorer Pipeline Company; Wolverine Pipe Line Company; West Shore Pipe Line Company; Yellowstone Pipe Line Company; Bayview Refining Company, LLC; and Permian Express Terminal LLC ("PET," formerly known as the SunVit Pipeline LLC). Equity income from the investments has been included based on our respective ownership percentages of each, and from the dates of acquisition or formation.
(2) 
In June 2014, a two-for-one split was completed, which resulted in the issuance of one additional common unit for every one unit owned. All unit and per unit information is presented on a post-split basis.

46



(3) 
Cash distributions paid per unit to limited partners represent payments made per unit during the period stated. Cash distributions declared per unit to limited partners represent distributions declared per unit for the quarters within the period stated. Declared distributions were paid within 45 days following the close of each quarter.
(4) 
Adjusted EBITDA and Distributable Cash Flow provide additional information for evaluating our ability to make distributions to our unitholders and our general partner. The following tables reconcile (a) the difference between net income, as determined under United States generally accepted accounting principles ("GAAP"), and Adjusted EBITDA and Distributable Cash Flow and (b) net cash provided by operating activities and Adjusted EBITDA:
 
 
Successor
 
 
Predecessor
 
 
Year Ended December 31,
 
Period from Acquisition,
October 5, 2012 to
December 31, 2012
 
 
Period from
January 1, 2012 to
October 4, 2012
2016
 
2015
 
2014
 
2013
 
 
 
 
(in millions)
 
 
(in millions)
Net Income
 
$
709

 
$
397

 
$
300

 
$
474

 
$
142

 
 
$
389

Interest expense, net
 
157

 
134

 
67

 
77

 
14

 
 
65

Depreciation and amortization expense
 
446

 
382

 
296

 
265

 
63

 
 
76

Impairment charge and other matters
 
(170
)
 
162

 
258

 

 

 
 
9

Provision for income taxes
 
27

 
21

 
25

 
30

 
8

 
 
24

Non-cash compensation expense
 
23

 
17

 
16

 
14

 
2

 
 
6

Unrealized (gains) losses on commodity risk management activities
 
39

 
4

 
(17
)
 
(1
)
 
(3
)
 
 
6

Amortization of excess equity method investment
 
2

 
2

 
2

 
2

 

 
 

Proportionate share of unconsolidated affiliates' interest, depreciation and provision for income taxes
 
41

 
34

 
24

 
20

 
5

 
 
16

Gain on investment in affiliate
 
(41
)
 

 

 

 

 
 

Non-cash accrued liability adjustment
 

 

 

 
(10
)
 

 
 

Adjustments to commodity hedges resulting from "push-down" accounting
 

 

 

 

 
(12
)
 
 

Adjusted EBITDA
 
1,233

 
1,153

 
971

 
871

 
219

 
 
591

Interest expense, net
 
(157
)
 
(134
)
 
(67
)
 
(77
)
 
(14
)
 
 
(65
)
Provision for current income taxes
 
(26
)
 
(15
)
 
(29
)
 
(24
)
 
(10
)
 
 
(24
)
Amortization of fair value adjustments on long-term debt
 
(9
)
 
(13
)
 
(14
)
 
(23
)
 
(6
)
 
 

Proportionate share of unconsolidated affiliates' interest, provision for current income taxes and maintenance capital expenditures (1)

 
(39
)
 
(40
)
 
(29
)
 
(23
)
 
(1
)
 
 
(20
)
Maintenance capital expenditures
 
(63
)
 
(84
)
 
(76
)
 
(53
)
 
(21
)
 
 
(29
)
Distributable Cash Flow attributable to noncontrolling interests
 
(3
)
 
(4
)
 
(12
)
 
(16
)
 
(2
)
 
 
(9
)
Contributions attributable to acquisition from affiliate
 
7

 
11

 
12

 
9

 

 
 

Distributable Cash Flow (1)
 
$
943

 
$
874

 
$
756

 
$
664

 
$
165

 
 
$
444

(1)
During the first quarter 2016, we changed our definition of distributable cash flow to conform to the presentation utilized by our general partner. The change did not have a material impact on our distributable cash flow. Prior period amounts have been recast to conform to current presentation.

47



 
 
Successor
 
 
Predecessor
 
 
Year Ended December 31,
 
Period from Acquisition,
October 5, 2012 to
December 31, 2012
 
 
Period from
January 1, 2012 to
October 4, 2012
2016
 
2015
 
2014
 
2013
 
 
 
 
 
(in millions)
 
 
(in millions)
Net cash provided by operating activities
 
$
888

 
$
598

 
$
566

 
$
749

 
$
280

 
 
$
411

Interest expense, net
 
157

 
134

 
67

 
77

 
14

 
 
65

Amortization of bond premium, discount and financing fees
 
9

 
13

 
12

 
22

 
6

 
 
(2
)
Deferred income tax (expense) benefit
 
(3
)
 
(5
)
 
4

 
(6
)
 
2

 
 

Regulatory matters excluded from Adjusted EBITDA
 

 

 

 

 

 
 
10

Claim for (recovery of) environmental liability
 

 

 

 

 
(13
)
 
 
14

Equity in earnings of unconsolidated affiliates
 
39

 
24

 
25

 
21

 
5

 
 
15

Distributions from unconsolidated affiliates
 
(25
)
 
(23
)
 
(14
)
 
(14
)
 
(6
)
 
 
(5
)
Net change in working capital pertaining to operating activities
 
46

 
361

 
258

 
(20
)
 
(91
)
 
 
29

Unrealized (gains) losses on commodity risk management activities
 
39

 
4

 
(17
)
 
(1
)
 
(3
)
 
 
6

Amortization of excess equity method investment
 
2

 
2

 
2

 
2

 

 
 

Proportionate share of unconsolidated affiliates' interest, depreciation and provision for income taxes
 
41

 
34

 
24

 
20

 
5

 
 
16

Non-cash accrued liability adjustment
 

 

 

 
(10
)
 

 
 

Adjustments to commodity hedges resulting from "push-down" accounting
 

 

 

 

 
(12
)
 
 

Provision for income taxes
 
27

 
21

 
25

 
30

 
8

 
 
24

Other
 
13

 
(10
)
 
19

 
1

 
24

 
 
8

Adjusted EBITDA
 
$
1,233

 
$
1,153

 
$
971

 
$
871

 
$
219

 
 
$
591

Our management believes Adjusted EBITDA and Distributable Cash Flow information enhances an investor's understanding of a business's performance, which is a factor in evaluating its ability to generate cash for payment of distributions and other purposes. In addition, our compliance with certain revolving credit facility covenants is measured using Adjusted EBITDA, as defined in the specific credit facility. However, there may be contractual, legal, economic or other reasons which may prevent us from satisfying principal and interest obligations with respect to indebtedness and may require us to allocate funds for other purposes. Adjusted EBITDA and Distributable Cash Flow do not represent and should not be considered alternatives to net income or cash flows from operating activities as determined under GAAP and may not be comparable to other similarly titled measures of other businesses.

 

48



 
 
Successor
 
 
Predecessor
Year Ended December 31,
 
Period from Acquisition,
October 5, 2012 to
December 31, 2012 (5)
 
 
Period from
January 1, 2012 to
October 4, 2012 (5)
2016 (1)
 
2015 (2)
 
2014 (3)
 
2013 (4)
 
 
 
 
(in millions)
 
 
(in millions)
Cash Flow Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
888

 
$
598

 
$
566

 
$
749

 
$
280

 
 
$
411

Net cash used in investing activities
 
$
(3,038
)
 
$
(2,854
)
 
$
(2,866
)
 
$
(957
)
 
$
(139
)
 
 
$
(224
)
Net cash provided by (used in) financing activities
 
$
2,154

 
$
2,192

 
$
2,362

 
$
244

 
$
(140
)
 
 
$
(190
)
Capital expenditures:
 
 
 
 
 
 
 
 
 
 
 
 
 
Expansion (6)
 
$
1,881

 
$
2,620

 
$
2,346

 
$
851

 
$
118

 
 
$
206

Maintenance (7)
 
68

 
86

 
70

 
46

 
21

 
 
29

Acquisitions
 
786

 
131

 
433

 
60

 

 
 

Total capital expenditures
 
$
2,735

 
$
2,837

 
$
2,849

 
$
957

 
$
139

 
 
$
235

(1) 
Cash flows related to expansion capital expenditures in 2016 included projects to: invest in the announced Mariner NGLs projects; invest in our crude oil infrastructure by increasing our pipeline capabilities through announced expansion capital and joint projects; expand the service capabilities of our acquisition and marketing activities; and upgrade the service capabilities at our bulk marine terminals. Cash flows related to acquisitions in 2016 included $769 million related to the acquisition of the Vitol Inc. ("Vitol") crude oil business, including an additional 50 percent ownership interest in the PET crude oil pipeline, and a $17 million acquisition related to the purchase of an additional ownership interest in the Explorer crude oil pipeline.
(2) 
Cash flows related to expansion capital expenditures in 2015 included projects to: invest in the previously announced Mariner NGLs projects and Allegheny Access pipeline project; invest in our crude oil infrastructure by increasing our pipeline capabilities through announced expansion capital and joint projects; expand the service capabilities of our acquisition and marketing activities; and upgrade the service capabilities at our bulk marine terminals. Cash flows related to acquisitions in 2015 included $131 million related to the acquisition of remaining ownership interest in the West Texas Gulf Pipe Line Company ("West Texas Gulf") crude oil pipeline.
(3) 
Cash flows related to expansion capital expenditures in 2014 included projects to: invest in the previously announced Mariner NGLs projects and Allegheny Access pipeline project; invest in our crude oil infrastructure by increasing our pipeline capabilities through previously announced expansion capital and joint projects in Texas and Oklahoma; expand the service capabilities of our acquisition and marketing activities; and upgrade the service capabilities at our bulk marine terminals. Cash flows related to acquisitions in 2014 included $65 million related to a crude oil acquisition and marketing business and a controlling financial interest in a related rail facility, $325 million related to the acquisition of additional ownership interest in West Texas Gulf, and $42 million related to the acquisition of additional ownership interest in Explorer Pipeline Company.
(4) 
Cash flows related to expansion capital expenditures in 2013 included projects to: invest in our crude oil infrastructure by increasing our pipeline capabilities through previously announced expansion capital projects in Texas and Oklahoma; expand upon our acquisition and marketing activities; upgrade the service capabilities at the Eagle Point and Nederland terminals; and invest in the previously announced Mariner and Allegheny Access projects. We also acquired the Marcus Hook Industrial Complex for $60 million in 2013.
(5) 
Cash flows related to expansion capital expenditures for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012 included projects to: expand upon our acquisition and marketing activities, upgrade the service capabilities at the Eagle Point and Nederland terminals; invest in our crude oil infrastructure by increasing our pipeline capabilities through previously announced growth projects in West Texas and expanding the crude oil trucking fleet; and to invest in the Mariner pipeline projects.
(6) 
Expansion capital expenditures are capital expenditures made to acquire and integrate complimentary assets and joint projects, to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume.
(7) 
Maintenance capital expenditures are capital expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations. We treat maintenance expenditures that do not extend the useful life of existing assets as operating expenses as incurred.


49



 
 
Successor
December 31,
2016
 
2015
 
2014
 
2013
 
2012
(in millions)
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
 
Net properties, plants and equipment
 
$
12,324

 
$
10,692

 
$
8,849

 
$
6,519

 
$
5,623

Total assets
 
$
18,849

 
$
15,489

 
$
13,618

 
$
11,890

 
$
10,361

Total debt
 
$
7,313

 
$
5,591

 
$
4,234

 
$
2,496

 
$
1,732

Total Sunoco Logistics Partners L.P. Equity
 
$
8,660

 
$
7,521

 
$
6,678

 
$
6,204

 
$
6,072

Noncontrolling interests
 
33

 
34

 
60

 
121

 
123

Total equity
 
$
8,693

 
$
7,555

 
$
6,738

 
$
6,325

 
$
6,195

 
 
 
Successor
 
 
Predecessor
 
 
Year Ended December 31,
 
Period from Acquisition, October 5, 2012 to December 31, 2012
 
 
Period from
January 1, 2012 to
October 4, 2012
2016
 
2015
 
2014
 
2013
 
 
 
Operating Data:
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude Oil (1) (2)
 
 
 
 
 
 
 
 
 
 
 
 
 
Pipeline throughput (thousands of barrels per day ("bpd")) (3)
 
2,423

 
2,225

 
2,125

 
1,866

 
1,584

 
 
1,546

Terminals throughput (thousands of bpd)
 
1,552

 
1,401

 
1,403

 
1,210

 
1,126

 
 
1,017

Gross Profit (millions of dollars) (4)
 
$
723

 
$
706

 
$
726

 
$
750

 
$
185

 
 
$
460

Natural Gas Liquids
 
 
 
 
 
 
 
 
 
 
 
 
 
Pipeline throughput (thousands of bpd)
 
277

 
209

 
33

 
9

 
9

 
 
19

Terminals throughput (thousands of bpd)
 
235

 
184

 
40

 
31

 
5

 
 
4

Gross Profit (millions of dollars) (4)
 
$
330

 
$
348

 
$
248

 
$
84

 
$
48

 
 
$
50

Refined Products (1)
 
 
 
 
 
 
 
 
 
 
 
 
 
Pipeline throughput (thousands of bpd) (3)
 
599

 
518

 
481

 
512

 
550

 
 
526

Terminals throughput (thousands of bpd)
 
557

 
534

 
497

 
525

 
523

 
 
554

Gross Profit (millions of dollars) (4)
 
$
148

 
$
123

 
$
65

 
$
83

 
$
13

 
 
$
86

(1) 
Excludes amounts attributable to equity ownership interests which are not consolidated.
(2) 
Throughputs related to the acquisition from Vitol have been included from the acquisition date.
(3) 
Prior period pipeline throughput amounts have been restated to conform to current presentation.
(4) 
Represents total segment sales and other operating revenue less costs of products sold and operating expenses.



50



ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the consolidated financial statements of Sunoco Logistics Partners L.P. Among other things, those consolidated financial statements include more detailed information regarding the basis of presentation for the following information.
Overview
We, Sunoco Logistics Partners L.P. or "SXL," are a Delaware limited partnership which operates a logistics business, consisting of a geographically diverse portfolio of integrated pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, natural gas liquids ("NGLs") and refined products. Our portfolio of geographically diverse assets earns revenues in 37 states located throughout the United States. Revenues are generated by charging tariffs for transporting crude oil, NGLs and refined products through our pipelines, as well as by charging fees for various services at our terminal facilities. Revenues are also generated by acquiring and marketing crude oil, NGLs and refined products. Generally, our commodity purchases are entered into in contemplation of or simultaneously with corresponding sale transactions involving physical deliveries, which enables us to secure a profit on the transaction at the time of purchase.
We are a consolidated subsidiary of Energy Transfer Partners, L.P. ("ETP"), the controlling member of our general partner. In addition to our general partner interest, ETP also owns 76.5 million common units and Class B units, which represents a 23.0 percent limited partner ownership interest in the Partnership and all of our incentive distribution rights.
On November 20, 2016, we and our general Partner, Sunoco Partners LLC ("SXL GP"), a Pennsylvania limited liability company, entered into an Agreement and Plan of Merger (the "Merger Agreement") with ETP, together with Energy Transfer Partners GP, L.P. ("ETP GP"), a Delaware limited partnership and the general partner of ETP, and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. ("ETE"), a Delaware limited partnership and indirect parent entity of ETP, ETP GP, the Partnership and SXL GP. Upon the terms and subject to the conditions set forth in the Merger Agreement, a wholly-owned subsidiary of SXL will merge with ETP (the "Merger"), with ETP continuing as the surviving entity and a wholly-owned subsidiary of SXL. Concurrently with the Merger, SXL GP will merge with ETP GP, with ETP GP continuing as the surviving entity and becoming the general partner of SXL. Following the recommendation of the conflicts committee (the "ETP Conflicts Committee") of the board of directors of ETP's managing general partner (the "ETP Board"), the ETP Board approved and agreed to submit the Merger Agreement to a vote of ETP unitholders and to recommend that ETP's unitholders adopt the Merger Agreement. Following the recommendation of the conflicts committee of the board of directors of SXL GP, the board of directors of SXL GP approved the Merger Agreement. The Merger is expected to close in April 2017.
Effective at the time of the Merger, all SXL units, 67.1 million common and 9.4 million Class B, currently held by ETP will be retired. The existing incentive distribution right ("IDR") provisions in the SXL Partnership Agreement will continue to be in effect, and ETE will own the IDRs of SXL following the closing of the transaction. As part of this transaction, ETE has agreed to continue to provide all the IDR subsidies that are currently in effect for both SXL and ETP. In addition, our 364-Day credit facility is expected to be terminated and repaid in connection with the Merger. Also effective at the time of the Merger, each common unit representing a limited partner interest in ETP issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time of the merger will be converted into the right to receive 1.50 common units representing limited partner interests in SXL (the "SXL Common Units") (the "Merger Consideration"). Each Class E Unit of ETP, each Class G Unit of ETP, each Class I Unit of ETP, each Class J Unit of ETP and each Class K Unit of ETP, if any, issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time of the Merger will be converted into the right to receive a corresponding unit in SXL with the same rights, preferences, privileges, powers, duties and obligations as such existing ETP unit had immediately prior to the Merger. The corresponding units in SXL will be issued pursuant to the Fourth Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., which will be executed at the effective time.
Strategic Actions
Our primary business strategies focus on generating stable cash flows by increasing pipeline and terminal throughput, utilizing our acquisition and marketing assets to maximize value, pursuing economically accretive organic growth opportunities, and continuing to improve operational efficiencies and reduce costs. We also utilize our pipeline systems to take advantage of market dislocations. We believe these strategies will result in continuing increases in distributions to our unitholders. As part of our strategy, we have undertaken several initiatives including the acquisitions and growth capital programs described below.



51



Acquisitions
For the three-year period ended December 31, 2016, we completed $1.4 billion in acquisitions:
Vitol Crude Oil - In November 2016, we acquired an integrated crude oil business in West Texas from Vitol Inc. ("Vitol"). The acquisition provided us with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol's crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50 percent interest in SunVit, which increased our overall ownership of SunVit to 100 percent.
Explorer Pipeline Company - In March 2014 and August 2016, we exercised rights to acquire additional 3.9 and 1.7 percent ownership interests, respectively, in Explorer Pipeline Company ("Explorer"), increasing our overall ownership interest from 9.4 to 15.0 percent. Our ownership interest continues to be reported as an equity method investment in our Refined Products segment.
West Texas Gulf Pipe Line Company - In December 2014, we acquired an additional 28.3 percent ownership interest in West Texas Gulf Pipe Line Company ("West Texas Gulf") from Chevron Pipe Line Company, increasing our controlling financial interest to 88.6 percent. The remaining noncontrolling interest in West Texas Gulf was acquired in January 2015. The pipeline is now wholly-owned and continues to be reported in our Crude Oil segment.
EDF Trading - In May 2014, we acquired a crude oil purchasing and marketing business from EDF Trading North America, LLC ("EDF"). The purchase consisted of a crude oil acquisition and marketing business and related assets which handle 20 thousand barrels per day. The acquisition also included a promissory note that was convertible to an equity interest in a rail facility (see Price River Terminal, below). The acquisition is included in our Crude Oil segment.
Price River Terminal - In May 2014, we acquired a 55 percent economic and voting interest in Price River Terminal, LLC ("PRT"), a rail facility in Wellington, Utah. The terms of the acquisition provide PRT's noncontrolling interest holders the option to sell their interests to the Partnership at a price defined in the purchase agreement. Since we acquired a controlling financial interest in PRT, the entity was reflected as a consolidated subsidiary from the acquisition date and is included in the Crude Oil segment.
Changes in Business and Other Matters
In February 2017, we formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil. We contributed our Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Our ownership percentage, upon formation, is approximately 85 percent. Upon commencement of operations on the Bakken pipeline, we will contribute our investment in the project, with a corresponding increase in our ownership percentage in PEP. We maintain a controlling financial and voting interest in PEP and are the operator of all of the assets contributed to the joint venture. As such, PEP will be reflected as a consolidated subsidiary with its operating results included in the Crude Oil segment. ExxonMobil's interest will be reflected as noncontrolling interest in our consolidated balance sheets.
Growth Capital Program
In 2016, we invested $1.8 billion in organic growth capital projects to improve operational efficiencies, reduce costs, expand existing facilities and construct new assets to increase throughput volume, storage, or the scope of services we are able to provide. These included projects to: invest in the announced Mariner NGLs projects; invest in our crude oil infrastructure by increasing our pipeline capabilities through announced expansion capital and joint projects; expand the service capabilities of our acquisition and marketing activities; and upgrade the service capabilities at our bulk marine terminals.
Expansion capital expenditures in 2017 will include continued progress on our previously announced growth projects:
Mariner East 2
Our Mariner East project transports NGLs from the Marcellus and Utica Shale areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including our Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 thousand barrels per day for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the third quarter 2017.

52



Bayou Bridge
The Bayou Bridge pipeline project consists of newly constructed pipeline that delivers crude oil from Nederland, Texas to refinery markets in Louisiana. Commercial operations from Nederland, Texas to Lake Charles, Louisiana commenced in the second quarter 2016, with continued progress on an extension of the pipeline segment to St. James, Louisiana, which is expected to commence operations in the fourth quarter 2017. The Bayou Bridge pipeline is a joint project with ETP and Phillips 66 ("P66"), and we are the operator of the pipeline.
Bakken
The Bakken project consists of existing and newly constructed pipelines that are expected to provide aggregate takeaway capacity of approximately 450 thousand barrels per day of crude oil from the Bakken/Three Forks production area in North Dakota to key refinery and terminalling hubs in the midwest and Gulf Coast, including our Nederland terminal. The ultimate takeaway capacity target for the project is 570 thousand barrels per day. The pipeline system is a joint project with ETP and P66, and we expect to reach agreement to become the operator of the pipeline system. Commercial operations are expected to commence in the second quarter 2017.
Conservative Capital Structure
Our goal is to maintain substantial liquidity and a conservative capital structure. Sunoco Logistics Partners Operations L.P. (the "Operating Partnership"), our wholly-owned subsidiary, maintains a $2.50 billion Credit Facility and a $1.0 billion 364-Day Credit Facility. At December 31, 2016, our total borrowing capacity under our facilities was $3.5 billion, which, under certain conditions, can be extended to $4.25 billion.
During 2016, we issued 53.3 million common units for net proceeds of $1.39 billion in connection with an overnight equity offering and activity under our at-the-market equity offering program ("ATM program"). We also issued $550 million of long-term debt in connection with senior notes offerings.
We will maintain our conservative capital structure by utilizing a combination of our operating cash flows and debt and equity issuances to finance our future growth.
Cash Distribution Increases
As a result of our continued growth, our general partner increased our cash distributions to limited partners in all quarters in the three years ended December 31, 2016. For the quarter ended December 31, 2016, the distribution increased to $0.52 per common unit ($2.08 annualized). The distribution for the fourth quarter 2016 was paid on February 14, 2017.
In connection with the acquisition from Vitol, our general partner executed an amendment to our Third Amended and Restated Agreement of Limited Partnership in September 2016, which provides for a reduction to the incentive distributions to be paid to our general partner. The reductions will total $60 million over a two-year period, recognized ratably over eight quarters, and began with the third quarter 2016 cash distribution.


53



Results of Operations
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except per unit data)
Statements of Income
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
Unaffiliated customers
$
8,715

 
$
9,971

 
$
17,018

Affiliates
436

 
515

 
1,070

Total revenues
9,151

 
10,486

 
18,088

Cost of products sold
7,828

 
9,145

 
16,877

Operating expenses
122

 
164

 
172

Selling, general and administrative expenses
110

 
103

 
118

Depreciation and amortization expense
446

 
382