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.

7


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.




8


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.



9


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.





















10


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.


11


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.





12


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.
  

13


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.

14


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.







16


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;
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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;
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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
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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

 
296

Impairment charge and other matters
(170
)
 
162

 
258

Total costs and expenses
8,336

 
9,956

 
17,721

Operating income
815

 
530

 
367

Net interest expense
(157
)
 
(134
)
 
(67
)
Gain on investment in affiliate
41

 
—

 
—

Other income
37

 
22

 
25

Income before provision for income taxes
736

 
418

 
325

Provision for income taxes
(27
)
 
(21
)
 
(25
)
Net Income
709

 
397

 
300

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

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

 
$
393

 
$
291

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

 
$
0.42

 
$
0.52

Diluted
$
0.98

 
$
0.42

 
$
0.51







54


Non-GAAP Financial Measures
To supplement our financial information presented in accordance with United States generally accepted accounting principles ("GAAP"), management uses additional measures that are known as "non-GAAP financial measures" in its evaluation of past performance and prospects for the future. The primary measures used by management are earnings before interest, taxes, depreciation and amortization expenses and other non-cash items ("Adjusted EBITDA") and Distributable Cash Flow ("DCF"). Adjusted EBITDA and DCF 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.
Our management believes that Adjusted EBITDA and DCF 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. Adjusted EBITDA calculations are also defined and used as a measure in determining our compliance with certain revolving credit facility covenants. However, despite compliance with our credit facility covenants, there may be contractual, legal, economic or other factors which may prevent us from satisfying principal and interest obligations with respect to indebtedness and may require us to allocate funds for other purposes.
The following table reconciles the differences between net income, as determined under GAAP, and Adjusted EBITDA and DCF:
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions)
Net Income
$
709

 
$
397

 
$
300

Interest expense, net
157

 
134

 
67

Depreciation and amortization expense
446

 
382

 
296

Impairment charge and other matters
(170
)
 
162

 
258

Provision for income taxes
27

 
21

 
25

Non-cash compensation expense
23

 
17

 
16

Unrealized (gains) losses on commodity risk management activities
39

 
4

 
(17
)
Amortization of excess equity method investment
2

 
2

 
2

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

 
34

 
24

Gain on investment in affiliate
(41
)
 
—

 
—

Adjusted EBITDA
1,233

 
1,153

 
971

Interest expense, net
(157
)
 
(134
)
 
(67
)
Provision for current income taxes
(26
)
 
(15
)
 
(29
)
Amortization of fair value adjustments on long-term debt
(9
)
 
(13
)
 
(14
)
Proportionate share of unconsolidated affiliates' interest, depreciation and provision for income taxes (1)

(39
)
 
(40
)
 
(29
)
Maintenance capital expenditures
(63
)
 
(84
)
 
(76
)
Distributable Cash Flow attributable to noncontrolling interests
(3
)
 
(4
)
 
(12
)
Contributions attributable to acquisition from affiliate
7

 
11

 
12

Distributable Cash Flow (1)
$
943

 
$
874

 
$
756

(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.




55


Analysis of Consolidated Operating Results
Net income attributable to Sunoco Logistics Partners L.P. ("net income attributable to SXL") was $705 and $393 million for the years ended December 31, 2016 and 2015, respectively. The increase was largely attributable to a $332 million positive variance related to non-cash inventory adjustments resulting from changes in commodity prices compared to the prior year period. Also contributing to the increase were higher operating results from our Crude Oil and Refined Products segments, including improved contributions from our joint venture interests, and a $41 million non-cash gain resulting from the acquisition of the remaining interest in SunVit. These positive factors were partially offset by lower operating results from our Natural Gas Liquids segment, higher depreciation and amortization expense related to expansion capital projects placed into service in 2015 and 2016, and higher net interest expense largely attributable to senior notes issued during both periods.
Net income attributable to SXL was $393 and $291 million for the years ended December 31, 2015 and 2014, respectively. The increase was largely attributable to a $96 million positive variance related to non-cash inventory adjustments resulting from changes in commodity prices compared to the prior year period. Also contributing to the increase were higher operating results from our Natural Gas Liquids and Refined Products segments. These positive impacts were largely offset by higher depreciation and amortization expense, higher net interest expense attributable to senior note offerings in 2015 and 2014, and lower operating results from our Crude Oil segment.
See "Analysis of Operating Segments" and "Liquidity and Capital Resources" below for additional details on our operating results.


56


Analysis of Operating Segments
We manage our operations through three operating segments: Crude Oil, Natural Gas Liquids, and Refined Products.
Crude Oil
Our Crude Oil segment utilizes an integrated set of pipeline, terminalling, and acquisition and marketing assets that facilitate the movement of crude oil from producers to end-user markets. The segment includes crude oil trunk and gathering pipelines in the southwest and midwest United States, including those owned by our joint venture interests, terminalling assets in key crude oil markets, and a crude oil trucking fleet that supports the sale of gathered and bulk purchased crude oil. Revenues are generated from tariffs and the associated fees paid by shippers utilizing our pipeline assets with rates for shipments on the crude oil pipelines regulated by the Federal Energy Regulatory Commission ("FERC") and other state regulatory agencies, as applicable. The Crude Oil segment also generates revenues from fees for terminalling services provided and the marketing of crude oil.
The crude oil acquisition and marketing activities generate substantial revenue and cost of products sold as a result of the significant volumes bought and sold. The absolute price levels of crude oil normally do not bear a relationship to gross profit, although the price levels significantly impact revenue and costs of products sold. 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 segment. The operating results of the Crude Oil segment are affected by overall levels of supply and demand for crude oil and relative fluctuations in market related indices. To the extent there are periods of sustained crude oil price declines, drilling activity could decline impacting the volume of crude oil we transport, store, or buy and sell. Generally, we expect a base level of earnings from our Crude Oil segment 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. Our management believes gross profit, which is equal to sales and other operating revenue less cost of products sold and operating expenses, is a key measure of financial performance. Although we implement risk management activities to provide general stability in our margins, these margins are not fixed and will vary from period to period.
The following table presents the operating results and key operating measures for our Crude Oil segment for the periods presented:
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except for barrel amounts)
Sales and other operating revenue
 
 
 
 
 
Unaffiliated customers
$
7,472

 
$
8,763

 
$
16,033

Affiliates
24

 
193

 
866

Total sales and other operating revenue
$
7,496

 
$
8,956

 
$
16,899

Depreciation and amortization expense
$
242

 
$
216

 
$
191

Impairment charge and other matters (1)
$
(148
)
 
$
150

 
$
231

Adjusted EBITDA
$
687

 
$
656

 
$
669

Pipeline throughput (thousands of barrels per day ("bpd")) (2) (3)
2,423

 
2,225

 
2,125

Terminal throughput (thousands of bpd) (2)
1,552

 
1,401

 
1,403

Gross profit (4)
$
723

 
$
706

 
$
726

(1) 
Represents non-cash inventory adjustments related to changes in commodity prices.
(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.
(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.
Adjusted EBITDA for the Crude Oil segment increased $31 million to $687 million for the year ended December 31, 2016 compared to the prior year period. The increase was largely due to improved results from our crude oil pipelines ($155 million) which benefited from the expansion capital projects which commenced operations in 2016 and 2015, and the fourth quarter 2016 acquisition from Vitol, including the remaining interest in SunVit. Higher results from our crude oil terminals ($31 million), largely related to our Nederland facility, and improved contributions from our crude oil joint venture interests ($16 million) also contributed to the increase. These positive factors were largely offset by a decrease in operating results from our crude oil acquisition and marketing activities ($166 million), which includes transportation and storage fees related to our crude oil pipelines and terminal facilities, due to lower crude oil differentials and decreased volumes compared to the prior year.

57


Adjusted EBITDA for the Crude Oil segment decreased $13 million to $656 million for the year ended December 31, 2015 compared to the prior year period. The decrease in Adjusted EBITDA was due primarily to lower results from our crude oil acquisition and marketing activities ($96 million) driven by reduced margins which were negatively impacted by contracted crude oil differentials compared to the prior year period. This impact was partially offset by higher results from our crude oil pipelines ($71 million) largely attributable to expansion projects placed into service in 2015 and 2014, and higher results from our crude oil terminals ($14 million).


58


Natural Gas Liquids
Our Natural Gas Liquids segment transports, stores, and executes acquisition and marketing activities utilizing an integrated network of pipeline assets in the northeast and southwest United States, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Revenues are generated from tariffs and the associated fees paid by shippers utilizing our pipeline assets, fees for terminalling services provided, and the marketing of NGLs. Rates for shipments on the NGLs pipelines are regulated by the FERC and other state and Canadian regulatory agencies, as applicable.
The following table presents the operating results and key operating measures for our Natural Gas Liquids segment for the periods presented:
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except for barrel amounts)
Sales and other operating revenue
 
 
 
 
 
Unaffiliated customers
$
700

 
$
961

 
$
825

Affiliates
175

 
204

 
134

Total sales and other operating revenue
$
875

 
$
1,165

 
$
959

Depreciation and amortization expense
$
105

 
$
76

 
$
30

Impairment charge and other matters (1)
$
(20
)
 
$
10

 
$
27

Adjusted EBITDA
$
317

 
$
333

 
$
203

Pipeline throughput (thousands of bpd)
277

 
209

 
33

Terminal throughput (thousands of bpd)
235

 
184

 
40

Gross profit (2)
$
330

 
$
348

 
$
248

(1) 
Represents non-cash inventory adjustments related to changes in commodity prices.
(2) 
Represents total segment sales and other operating revenue less costs of products sold and operating expenses.
Adjusted EBITDA for the Natural Gas Liquids segment decreased $16 million to $317 million for the year ended December 31, 2016 compared to the prior year period. The decrease was largely attributable to lower operating results from our NGLs acquisition and marketing activities ($106 million) due to lower volumes and margins compared to the prior year. These factors were largely offset by increased volumes and fees from our Mariner NGLs projects ($90 million), which includes our NGLs pipelines and Marcus Hook and Nederland facilities.
Adjusted EBITDA for the Natural Gas Liquids segment increased $130 million to $333 million for the year ended December 31, 2015 compared to the prior year period. The increase in Adjusted EBITDA was due primarily to contributions from our Mariner NGLs projects which commenced operations in late 2014 and 2013. These projects contributed to improved results related to our NGLs pipeline and terminal operations ($160 million), including our Nederland and Marcus Hook facilities. These positive impacts were partially offset by lower results from our NGLs acquisition and marketing activities ($33 million) driven largely by narrowed blending margins compared to the prior year period.


59


Refined Products
Our Refined Products segment provides transportation and terminalling services through the use of refined products pipelines and approximately 40 active refined products marketing terminals. The segment includes our controlling financial interest in Inland Corporation ("Inland"), as well as equity ownership interest in four refined products pipelines. The Refined Products segment utilizes our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in the northeast and midwest United States. Revenues generated from tariffs and the associated fees paid by shippers utilizing our pipeline assets, fees for terminalling services provided, and the marketing of refined products. Rates for shipments on the refined products pipelines are regulated by the FERC and other associated state entities.
The following table presents the operating results and key operating measures for our Refined Products segment for the periods presented:
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
(in millions, except for barrel amounts)
Sales and other operating revenue
 
 
 
 
 
Unaffiliated customers
$
543

 
$
247

 
$
160

Affiliates
237

 
118

 
70

Total sales and other operating revenue
$
780

 
$
365

 
$
230

Depreciation and amortization expense
$
99

 
$
90

 
$
75

Impairment charge and other matters (1)
$
(2
)
 
$
2

 
$
—

Adjusted EBITDA
$
229

 
$
164

 
$
99

Pipeline throughput (thousands of bpd) (2) (3)
599

 
518

 
481

Terminal throughput (thousands of bpd)
557

 
534

 
497

Gross profit (4)
$
148

 
$
123

 
$
65

(1) 
Represents non-cash inventory adjustments related to changes in commodity prices.
(2) 
Excludes amounts attributable to equity ownership interests which are not consolidated.
(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.
Adjusted EBITDA for the Refined Products segment increased $65 million to $229 million for the year ended December 31, 2016 compared to the prior year period. The increase was driven primarily by improved operating results from our refined products pipelines ($32 million), which benefited from higher volumes on our Allegheny Access pipeline, and higher results from our refined products acquisition and marketing activities ($21 million). Improved contributions from our refined product joint venture interests ($6 million) and higher earnings attributable to our refined products terminals ($5 million) also contributed to the current year improvement.
Adjusted EBITDA for the Refined Products segment increased $65 million to $164 million for the year ended December 31, 2015 compared to the prior year period. The increase in Adjusted EBITDA was due primarily to higher results from our refined products pipelines ($33 million) driven largely by the commencement of operations on our Allegheny Access project in 2015. Terminalling activities at our refined products marketing terminals, as well as our Eagle Point and Marcus Hook facilities, increased compared to the prior year period ($15 million). Higher contributions from our joint venture interests ($10 million) and refined products acquisition and marketing activities ($6 million) also contributed to the increase.




60


Liquidity and Capital Resources
Liquidity
Cash generated from operations and borrowings under our credit facilities are our primary sources of liquidity. At December 31, 2016, we had a net working capital surplus of $768 million and available borrowing capacity of $1.6 billion under our credit facilities, including our commercial paper program. We supplement our cash flows from operations with proceeds from our ATM program, borrowings under our credit facilities, and periodically with debt and equity financing activities.
Capital Resources
Credit Facilities
We maintain a $2.50 billion unsecured revolving credit agreement (the "$2.50 billion Credit Facility"), which matures in March 2020, to fund our working capital requirements, finance acquisitions and capital projects, and for general partnership purposes. The $2.50 billion Credit Facility contains an "accordion" feature, under which the total aggregate commitment may be extended to $3.25 billion under certain conditions. In September 2015, we initiated a commercial paper program under the borrowing limits established by our $2.50 billion Credit Facility. In June 2015, the $2.50 billion Credit Facility was amended to create a segregated tranche of borrowings that will be guaranteed by ETP in connection with our investment in the Bakken pipeline project. The amendment did not modify the outstanding borrowings, total capacity or terms of the facility. Outstanding borrowings amounted to $1.3 billion and $562 million at December 31, 2016 and 2015, respectively. Borrowings under the $2.50 billion Credit Facility at December 31, 2016 included $50 million of commercial paper.
The $2.50 billion Credit Facility contains various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The credit facility also limits us, on a rolling four quarter basis, to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Our ratio of total consolidated debt to consolidated Adjusted EBITDA was 4.4 to 1 at December 31, 2016, as calculated in accordance with the credit agreement.
In December 2016, we entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility") with a total lending capacity of $1.0 billion, including a $630 million term loan. The terms of the 364-Day Credit Facility are similar to those of the $2.50 billion Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants on our ratio of debt to Adjusted EBITDA. The facility will be used to fund our working capital requirements and for general partnership purposes. The facility bears interest at LIBOR or the Base Rate (as defined in the facility), each plus an applicable margin. The credit facility may be repaid at any time, and is expected to be terminated and repaid in connection with completion of the Merger.
Senior Notes
In 2016, we issued $550 million of 3.90 percent Senior Notes due in 2026.
In 2015, we issued $600 million of 4.40 percent Senior Notes and $400 million of 5.95 percent Senior Notes due in 2021 and 2025, respectively.
In 2014, we issued $500 million of 4.25 percent Senior Notes, $700 million of 5.30 percent Senior Notes, and $800 million of 5.35 percent Senior Notes, due in 2024, 2044 and 2045, respectively.
We had $175 million of 6.125 percent Senior Notes and $175 million of 8.75 percent Senior Notes which matured and were repaid in May 2016 and February 2014, respectively, with borrowings under our $2.50 billion Credit Facility.
The net proceeds from senior notes offerings in 2016, 2015 and 2014 of $544, $991, million and $1.98 billion, respectively, were used to repay outstanding borrowings under our credit facilities and for general partnership purposes. The terms and conditions of the senior notes offered during these periods are comparable to those under our other outstanding senior notes.
Equity Offerings
We maintain an ATM program which allows us to issue common units directly to the public and raise capital in a timely and efficient manner to finance our growth capital program, while supporting our investment grade credit ratings. For the years ended December 31, 2016, 2015 and 2014, we issued 29.1, 26.8, and 10.3 million common units under the program, for net proceeds of $744, $890, and $477 million, respectively.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.

61


In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under our $2.50 billion Credit Facility and for general partnership purposes.
In September 2014, we completed an overnight public offering of 7.7 million common units for net proceeds of $362 million.
The net proceeds from the 2015 and 2014 offerings were used to repay outstanding borrowings under the $2.50 billion Credit Facility and for general partnership purposes.
Bakken Project Initiatives
In August 2016, ETP, Sunoco Logistics and Phillips 66 established a $2.5 billion project-level credit facility to provide substantially all of the remaining capital necessary to complete the project. The facility was limited to $1.1 billion in borrowings until attainment of certain closing conditions, which were met in February 2017. The joint partners agreed to provide the Bakken entities with a short-term loan until the full capacity of the $2.5 billion credit facility was available. The loan was made by the partners in proportion to their respective ownership interests. The note receivable due to the Partnership amounted to $301 million at December 31, 2016, and was repaid in February 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.



62


Cash Flows and Capital Expenditures
Operating Activities
Cash flows from operating activities are primarily driven by earnings, excluding the impact of non-cash items; the timing of cash receipts and disbursements related to accounts receivable and payable; and the timing of inventory transactions and changes in other working capital amounts. Non-cash items include depreciation and amortization expense, compensation expense and lower of cost or market adjustments related to changes in inventory commodity prices. See the Analysis of Consolidated Operating Results, above, for more information on changes in our consolidated earnings.
Net cash provided by operating activities in 2016 of $888 million was primarily the result of net income of $709 million and a non-cash adjustment for depreciation and amortization totaling $446 million. These sources of cash were partially offset by a $170 million non-cash inventory adjustment related to changes in commodity prices, a $41 million gain on an investment in affiliate and a $46 million increase in working capital largely attributable to an increase in our inventories.
Net cash provided by operating activities in 2015 of $598 million was primarily the result of net income of $397 million, adjusted for non-cash charges for depreciation and amortization totaling $382 million and a non-cash inventory write down of $162 million resulting from declining commodity prices. These sources of cash were partially offset by a $361 million increase in working capital largely attributable to an increase in inventory volumes in order to capture the contango market structure.
Net cash provided by operating activities in 2014 of $566 million was primarily the result of net income of $300 million, adjusted for non-cash charges for depreciation and amortization totaling $296 million and a non-cash inventory adjustment of $258 million resulting from declining commodity prices. These sources of cash were partially offset by a $258 million increase in working capital largely attributable to a decrease in net payables and an increase in inventory volumes.
Investing Activities
Cash flows used in investing activities relate primarily to our capital expenditures, including maintenance and expansion capital expenditures, acquisitions and investments in joint venture interests. See "Capital Requirements" below for additional details on our investing activities.
Expansion and maintenance capital expenditures amounted to $1.9 billion, $2.7 billion, and $2.4 billion in 2016, 2015 and 2014, respectively. Other sources of cash used in investing activities consisted largely of acquisitions and investments in joint venture interests, which amounted to $786, $131, and $433 million, respectively, in 2016, 2015 and 2014. Net cash used in investing activities in 2016 also included a $301 million increase in an affiliated note receivable related to the Bakken project.
Financing Activities
Cash flows from financing activities relate primarily to the payment of distributions to partners; proceeds from senior notes offerings, as well as overnight equity and ATM program offerings; borrowings and repayments under our credit facilities; and changes to advances to affiliated companies, which prior to our transition away from Sunoco's cash management program in 2014, represented our cash held by Sunoco in connection with our participation in that program.
Net cash provided by financing activities of $2.2 billion in 2016 primarily related to $1.4 billion of net proceeds from the issuance of common units; $1.4 billion of net borrowings under our credit facilities; and $544 million of net proceeds from a senior notes offering. These sources of cash were partially offset by $961 million in distributions paid to partners, and repayment of the $175 million 6.125 percent Senior Notes in May 2016.
Net cash provided by financing activities of $2.2 billion in 2015 was primarily related to $1.5 billion of net proceeds from the issuance of common units, $991 million of net proceeds related to a senior notes offering and $377 million of net borrowings under our $2.50 billion Credit Facility. These sources of cash were partially offset by $686 million of distributions paid to partners.
Net cash provided by financing activities of $2.4 billion in 2014 was primarily related to $1.98 billion of net proceeds related to senior notes offerings; $839 million of net proceeds from the issuance of common units; and the $239 million decrease in advances to affiliates. These sources of cash were partially offset by $468 million of distributions paid to partners; the $175 million repayment of senior notes which matured in February 2014; and $50 million of net credit facility repayments.






63


Capital Requirements
Our operations are capital intensive, requiring significant investment to maintain, upgrade and enhance existing assets and to meet environmental and operational regulations. The capital requirements have consisted, and are expected to continue to consist, primarily of:
•
Expansion capital expenditures to acquire and integrate complementary assets to improve operational efficiencies or reduce costs and to expand existing and construct new facilities, such as projects that increase storage or throughput volume, and joint projects which complement our existing asset base,
•
Maintenance capital expenditures that extend the usefulness of existing assets, such as those required to maintain equipment reliability, tankage and pipeline integrity and safety, and to address environmental regulations, and
•
Acquisitions to acquire and integrate complementary assets to grow the business, to improve operational efficiencies or reduce costs.
The following table summarizes maintenance and expansion capital expenditures, including amounts paid for acquisitions, for the years ended December 31, 2016, 2015 and 2014:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Expansion
 
$
1,849

 
$
2,625

 
$
2,483

Maintenance
 
63

 
84

 
76

Acquisitions
 
796

 
131

 
448

Total
 
$
2,708

 
$
2,840

 
$
3,007

Expansion capital expenditures for the years ended December 31, 2016, 2015 and 2014 consisted primarily of projects to: invest in the previously announced Mariner East 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.
Maintenance capital expenditures for the periods presented primarily included recurring expenditures such as pipeline integrity costs; pipeline relocations; repair and upgrade of field instrumentation, including measurement devices; repair and replacement of tank floors and roofs; upgrades of cathodic protection systems; crude trucks and related equipment; and the upgrade of pump stations.
In November 2016, we completed acquisition of an integrated crude oil business in West Texas from Vitol for $760 million plus working capital. 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 Pipeline LLC ("SunVit"), which increased our overall ownership of SunVit to 100 percent. Acquisitions in 2016 also included the purchase of an additional ownership interest in Explorer Pipeline Company increased our total ownership interest in the pipeline to 15.0 percent.
Acquisitions in 2015 included the purchase of the remaining noncontrolling interest in West Texas Gulf. Acquisitions in 2014 included the purchase of additional ownership interest in West Texas Gulf, the purchase of a crude oil acquisition and marketing business, the acquisition of a controlling financial interest in a crude oil rail facility, and the purchase of additional ownership interest in Explorer Pipeline Company.
Our capital expenditures, including any acquisitions, are generally funded from cash provided by operations, borrowings under our credit facilities, and with proceeds from debt and equity offerings, as necessary.






64


Contractual Obligations
The following table sets forth the aggregate amount of long-term debt maturities, purchase commitments related to future periods, and annual rentals applicable to non-cancelable operating leases at December 31, 2016:
 
 
Year Ended December 31,
 
Thereafter
 
Total
 
 
2017
 
2018
 
2019
 
2020
 
2021
 
 
 
(in millions)
Long-term debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Principal
 
$
630

 
$
—

 
$
—

 
$
1,542

 
$
600

 
$
4,500

 
$
7,272

Interest
 
298

 
287

 
287

 
263

 
238

 
3,186

 
4,559

Operating leases
 
7

 
4

 
3

 
3

 
—

 
—

 
17

Purchase obligations
 
4,286

 
493

 
420

 
309

 
305

 
779

 
6,592

 
 
$
5,221

 
$
784

 
$
710

 
$
2,117

 
$
1,143

 
$
8,465

 
$
18,440

Our operating leases, as reported above, include leases of office space, third-party pipeline capacity, and other property and equipment with initial or remaining non-cancelable terms in excess of one year.
A purchase obligation is an enforceable and legally binding agreement to purchase goods and services that specifies significant terms, including: fixed or expected quantities to be purchased; market-related pricing provisions; and a specified term. Our purchase obligations consist primarily of non-cancelable contracts to purchase crude oil, NGLs and refined products for terms of one year or less to support our acquisition and marketing activities.
A significant portion of the above purchase obligations relate to actual crude oil purchases for the month of January 2017. The remaining crude oil purchase obligation amounts are based on the quantities committed to be purchased, assuming adequate well production for the remainder of the year, at December 31, 2016 crude oil prices. Actual amounts to be paid in regards to these obligations will be based upon market prices or formula-based market prices during the period of purchase. For further discussion of our crude oil acquisition and marketing activities, see Item 1. "Business—Crude Oil."
Off-Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.
Environmental Matters
Operation of the pipelines, terminals, and associated facilities are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As a result of compliance with these laws and regulations, liabilities have been accrued for estimated site restoration costs to be incurred in the future at the facilities and properties, including liabilities for environmental remediation obligations. Under our accounting policies, liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. For a discussion of the accrued liabilities and charges against income related to these activities, see Note 11 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."
Under the terms of the Omnibus Agreement and in connection with the contribution of assets to us by affiliates of Sunoco, Sunoco has agreed to indemnify us for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the February 2002 initial public offering ("IPO"). See "Agreements with Related Parties" below for additional information.
For more information concerning environmental matters, see Item 1. "Business—Environmental Regulation."
Impact of Inflation
Although the impact of inflation has slowed in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace properties, plants, and equipment and may increase the costs of labor and supplies. To the extent permitted by competition, regulation, and existing agreements, we have and will continue to pass along increased costs to customers in the form of higher fees.



65


Critical Accounting Policies
A summary of our significant accounting policies is included in Note 2 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data." Management believes that the application of these policies on a consistent basis enables us to provide the users of the consolidated financial statements with useful and reliable information about our operating results and financial condition. The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Critical items that are subject to such estimates and assumptions include long-lived assets (including intangible assets), goodwill, and environmental remediation activities. Although management bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, actual results may differ from the estimates on which our consolidated financial statements are prepared at any given point in time.
The critical accounting policies identified by our management are as follows:
Long-Lived Assets
The cost of long-lived assets (less estimated salvage value, in the case of properties, plants and equipment), is generally depreciated on a straight-line basis over the estimated useful lives of the assets. Useful lives are based on historical experience, contract expiration or other reasonable basis, and are adjusted when changes in planned use, technological advances or other factors indicate that a different life would be more appropriate. Changes in useful lives that do not result in the impairment of an asset are recognized prospectively.
Our long-lived assets include identifiable intangible assets, which are comprised of customer relationships and technology related assets for our patented technology associated with our butane blending services. Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations or asset purchases whereby (i) we acquired information about or access to customers, (ii) the customers now have the ability to transact business with us and (iii) we are positioned due to limited competition to provide products or services to the customers. The customer relationship intangible assets are generally amortized on a straight-line basis over their respective economic lives. Technology related intangible assets consist of our patents for the blending of butane into refined products. These patents are amortized over their remaining legal lives. The value assigned to these intangible assets is amortized through depreciation and amortization expense, over a weighted average amortization period of approximately 17 years.
Long-lived assets are reviewed for impairment whenever events or circumstances indicate that the carrying amount of the assets may not be recoverable. Such events and circumstances include, but are not limited to: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under "Forward-Looking Statements" in this document.
A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. Such estimated future cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. The impairment recognized is the amount by which the carrying amount exceeds the fair market value of the impaired asset. It is often difficult to precisely estimate fair market value because quoted market prices for our long-lived assets may not be readily available. Therefore, fair market value is generally based on the present values of estimated future cash flows using discount rates commensurate with the risks associated with the assets being reviewed for impairment.
There were no long-lived asset impairments identified during the 2014 through 2016 period.
Goodwill
Goodwill represents the excess of consideration transferred plus the fair value of noncontrolling interests of an acquired business over the fair value of net assets acquired. Goodwill is not amortized; however it is tested for impairment annually or more often if warranted by events or changes in circumstances indicating that the carrying value may exceed the estimated fair value. Inherent in estimating fair value for each reporting unit are certain judgments and estimates relating the market multiples for comparable businesses, management's interpretation of current economic indicators and market conditions and assumptions about our strategic plans with regards to our operations. To the extent additional information arises, market conditions change or our strategies change, it is possible the conclusion regarding whether the goodwill is impaired could change and result in future goodwill impairment charges.


66


Management's process for evaluating goodwill for impairment involves estimating the fair value of our reporting units that contain goodwill. During the fourth quarter 2015, we realigned our reporting segments and, in accordance with accounting guidance, were required to test our goodwill balance for impairment both before and after the change in our reportable segments. Due to volatility within the energy markets, we utilized the assistance of a third party valuation firm in 2015 to develop models to estimate the fair value of each of our reporting units that contain goodwill.
During 2015, fair value was estimated using a combination of discounted cash flow and the market multiple methodologies. Under the discounted cash flow methodology, fair value was estimated using the present value of Management's projected cash flows for each reporting unit which was calculated using the expected return a market participant would require for each reporting unit. Under the market multiple methodology, a selection of peer group companies, which are similar from an operational or industry perspective, were considered in estimating market multiples. These multiples were applied to Management's projected Adjusted EBITDA in order to estimate fair value.
There were no goodwill impairments identified during the 2014 through 2016 period. For additional information on our current year impairment test, see Note 2 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."
Environmental Remediation
At December 31, 2016, our accrual for environmental remediation activities was $4 million. This accrual is for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual is undiscounted and is based on currently available information regarding estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. In the above instances, if a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in the range is accrued. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are also reflected in the accruals to the extent their occurrence is probable and reasonably estimable.
Management believes that none of the current remediation projects are material, individually or in the aggregate, to our financial position at December 31, 2016. As a result, our exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental regulations occur, such changes could impact several of our facilities. As a result, from time to time, significant charges against income for environmental remediation may occur.
Under the terms of the Omnibus Agreement and in connection with the contribution of assets to us by affiliates of Sunoco, Sunoco has agreed to indemnify us, in whole or in part, for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the IPO. We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify us. See "Agreements with Related Parties" for additional information.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites; the determination of the extent of the contamination at each site; the timing and nature of required remedial actions; the technology available and needed to meet the various existing legal requirements; the nature and terms of cost sharing arrangements with other potentially responsible parties; the nature and extent of future environmental laws; inflation rates and the determination of our liability at the sites, if any, in light of the number, participation level and financial viability of other parties.
New Accounting Pronouncements
For a discussion of recently issued accounting pronouncements, see Note 2 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."





67


Agreements with Related Parties
Acquisition of Sunoco
ETP acquired our general partner and certain limited partner interests in the fourth quarter 2012. We have various operating and administrative agreements with ETP and its affiliates, including the agreements described below. ETP and its affiliates perform the administrative functions defined in such agreements on our behalf.
Service and Commodity Sales Agreements
We are party to various agreements with ETP and our affiliates to provide pipeline, terminalling and storage services. We also have agreements for the purchase and sale of crude oil, NGLs and refined products. This activity is reflected in affiliated revenues in the consolidated statements of comprehensive income.
We are party to the following commercial agreements with our affiliated entities:
•
Pipeline Operator Agreement: We have agreements with certain of our joint venture interests to serve as operators of their respective pipeline systems. The agreements include a specified management fee and have either a defined termination date or are able to be terminated by both parties in certain cases.
•
Refined Product Terminal Services Agreement: We have a five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products at our terminals. The agreement contains no minimum throughput obligations for Sunoco. The agreement runs through February 2017.
•
Fort Mifflin Terminal Services Agreement: We have an agreement with Philadelphia Energy Solutions ("PES") relating to the Fort Mifflin terminal complex. Under this agreement, PES will deliver a minimum average of 300 thousand bpd of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin terminal complex; however, we are obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. We executed a 10-year agreement with PES in September 2012. We had a previous agreement with Sunoco which included terms similar to those contained in the agreement with PES.
These agreements also provide PES with the option to purchase the Fort Mifflin and Belmont terminals if certain triggering events occur, including a sale of substantially all of the assets or operations of the Philadelphia refinery, an initial public offering, or a public debt filing of more than $200 million. The purchase price for each facility would be established based on a fair value amount determined by designated third parties.
•
Inter-Refinery Pipeline Lease: In September 2012, Sunoco assigned its lease for the use of our inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67 percent each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse us for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2014 through 2016.
•
Marcus Hook Industrial Complex Storage and Terminalling Services: In connection with our second quarter 2013 acquisition of the Marcus Hook Industrial Complex, we assumed an agreement to provide butane storage and terminalling services to PES at the facility. The 10 year agreement extends through September 2022.
•
Refined Products Storage Agreements: We have agreements with an affiliated entity to utilize storage services at the Mont Belvieu, Texas and Hattiesburg, Mississippi terminal locations. The agreements run through November 2018.
•
Purchase and Sale Agreements: We have agreements for the purchase and sale of crude oil, NGLs and refined products with affiliated entities. These agreements are negotiated at market-based rates, do not extend beyond 2017, and can be terminated by either party in certain cases.
•
Terminalling Services: We have agreements with affiliates for the use of our terminal assets. The agreements are based on market terms and negotiated based on the respective term. These agreements vary in duration and can be terminated by either party in certain cases.
•
Pipeline Agreements: We have agreements with affiliated parties to utilize our pipelines to supply their business needs. All pipeline movements are on the same terms that would be available to unaffiliated customers under similar terms and are based on published tariff rates on the respective pipeline.




68


Omnibus Agreement
In 2002, we entered into an Omnibus Agreement with Sunoco and our general partner that addresses the following matters:
•
our obligation to pay the general partner or Sunoco an annual administrative fee for the provision by Sunoco and its affiliates of certain general and administrative services;
•
an indemnity by Sunoco for certain environmental, toxic tort and other liabilities; and
•
our obligation to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities related to the assets to the extent Sunoco is not required to indemnify us.
Administrative Services
We have no employees and we reimburse our general partner and its affiliates for certain costs and other direct expenses incurred on our behalf. In addition, we have incurred additional general and administrative costs which we pay directly.
Under the Omnibus Agreement, we pay ETP an annual administrative fee that includes expenses incurred by ETP and its affiliates to perform centralized corporate functions, such as legal, accounting, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. The conditions of Section 4.1 of the Omnibus Agreement (which concerns our obligation to pay the annual fee for provision of certain general and administrative services) have been extended annually by one year since the expiration of the initial term (through 2004). The costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by us. We are also allocated a component of shared insurance costs incurred by ETP and its affiliates. The amounts incurred in connection with the centralized corporate functions and shared insurances costs were not material to our results of operations during the three year period ended December 31, 2016.
We participate in various employee benefit programs as administered by ETP and its affiliates. Our share of allocated employee benefit plan expenses, including defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $61, $54, and $45 million for the years ended December 31, 2016, 2015 and 2014, respectively. These expenses are reflected in operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income.
Indemnification
Under the terms of the Omnibus Agreement and in connection with the contribution of assets by affiliates of Sunoco, Sunoco has agreed to indemnify us for 30 years from environmental and toxic tort liabilities related to the assets contributed that arise from the operation of such assets prior to closing of the IPO. Sunoco is obligated to indemnify us for 100 percent of all losses asserted within the first 21 years of closing of the IPO. Sunoco's share of liability for claims asserted thereafter will decrease by 10 percent per year. For example, for a claim asserted during the twenty-third year after closing of the IPO, Sunoco would be required to indemnify us for 80 percent of the loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. In addition, this indemnification applies to the following, purchased from Sunoco subsequent to the IPO: interests in the Mesa Pipeline System, Mid-Valley and Inland, as well as the Eagle Point assets and various other assets. Any environmental and toxic tort liabilities not covered by this indemnity will be our responsibility. Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites; the determination of the extent of the contamination at each site; the timing and nature of required remedial actions; the technology available and needed to meet the various existing legal requirements; the nature and extent of future environmental laws; inflation rates; and the determination of the liability at multi-party sites, if any, in light of the number, participation levels, and financial viability of other parties. We have agreed to indemnify Sunoco and its affiliates for events and conditions associated with the operation of the assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify us.
Sunoco has also agreed to indemnify us for liabilities relating to:
•
the assets contributed to SXL, other than environmental and toxic tort liabilities, that arise out of the operation of the assets prior to the closing of the IPO and that are asserted within ten years after the closing of the IPO;
•
certain defects in title to the assets contributed to SXL and failure to obtain certain consents and permits necessary to conduct the business that arise within ten years after the closing of the IPO;
•
legal actions related to the period prior to the IPO currently pending against Sunoco or its affiliates; and
•
events and conditions associated with any assets retained by Sunoco or its affiliates.

 

69


ITEM 7A.    
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to various market risks, including changing interest rates and volatility in market price of commodities such as crude oil, NGLs and refined products. To manage such exposure, interest rates, inventory levels and expectations of forward commodity prices are monitored when making decisions with respect to risk management.
Interest Rate Risk
We have interest rate risk exposure for changes in interest rates relating to our outstanding borrowings. We manage our exposure to changing interest rates through the use of a combination of fixed- and variable-rate debt. At December 31, 2016, we had $1.9 billion of variable-rate borrowings under our credit facilities. Outstanding borrowings bear interest cost of LIBOR plus an applicable margin. An increase in short-term interest rates will have a negative impact on funds borrowed under variable-rate debt arrangements. The weighted average variable interest rate on our variable-rate borrowings was approximately 2 percent at December 31, 2016. A one percent change in the weighted average rate would have impacted annual interest expense by approximately $12 million for the year ended December 31, 2016.
At December 31, 2016, we had $5.4 billion of fixed-rate borrowings which was comprised of our outstanding senior notes. This amount excludes the $84 million premium resulting from the adjustment of our assets and liabilities to fair value resulting from the application of push-down accounting in connection with the acquisition of the general partner by ETP. The estimated fair value of our senior notes was $5.4 billion at December 31, 2016. A hypothetical one-percent movement in interest rates would have impacted the fair value of our fixed-rate borrowings at December 31, 2016 by approximately $536 million.
Commodity Market Risk
We are exposed to volatility in crude oil, NGLs and refined products commodity prices. To manage such exposures, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management. Our policy is to purchase only commodity products for which we have a market and to structure our sales contracts so that price fluctuations for those products do not materially affect the margins we receive. We also seek to maintain a position that is substantially balanced within our various commodity purchase and sales activities. We may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances, as well as logistical issues associated with inclement weather conditions. When unscheduled physical inventory builds or draws do occur, they are monitored and managed to a balanced position over a reasonable period of time.
We do not use futures or other derivative instruments to speculate on crude oil, NGLs or refined products prices, as these activities could expose us to significant losses. We do use derivative contracts as economic hedges against price changes related to our forecasted crude oil, NGLs and refined products purchase and sales activities with contracts intended to have equal and opposite effects of the purchase and sales activities. At December 31, 2016, the fair market value of our open derivative positions was a net liability of $27 million on 9.2 million barrels, comprised of crude oil, NGLs and refined products instruments. These derivative positions vary in length but do not extend beyond one year. A hypothetical ten percent adverse change in year-end market prices of the underlying commodities being hedged by derivative contracts would have resulted in an estimated $22 million increase in market value at December 31, 2016. This hypothetical loss was estimated by multiplying the difference between the hypothetical and the actual year-end market prices of the underlying commodities by the contracted volume amounts.
For additional information concerning our commodity market risk activities, see Note 15 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."


70


ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Sunoco Logistics Partners L.P. (the "Partnership") is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. The Partnership's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with U.S. generally accepted accounting principles.
The Partnership's management assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2016. In making this assessment, the Partnership's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in the 2013 Internal Control—Integrated Framework.
Based on this assessment, management believes that, as of December 31, 2016, the Partnership's internal control over financial reporting is effective based on those criteria. Grant Thornton LLP, an independent registered public accounting firm, has issued an attestation report on the effectiveness of the Partnership's internal control over financial reporting, which appears in this section.
Michael J. Hennigan
President and Chief Executive Officer
Peter J. Gvazdauskas
Chief Financial Officer and Treasurer

71


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
Sunoco Partners LLC and Limited Partners of Sunoco Logistics Partners L.P.

We have audited the internal control over financial reporting of Sunoco Logistics Partners L.P. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2016, and our report dated February 24, 2017 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP
Philadelphia, Pennsylvania
February 24, 2017

72


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
Sunoco Partners LLC and Limited Partners of Sunoco Logistics Partners L.P.

We have audited the accompanying consolidated balance sheets of Sunoco Logistics Partners L.P. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sunoco Logistics Partners L.P. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2017 expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP
Philadelphia, Pennsylvania
February 24, 2017







73


SUNOCO LOGISTICS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions, except per unit amounts)
 
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Revenues
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
Unaffiliated customers
 
$
8,715

 
$
9,971

 
$
17,018

Affiliates (Note 4)
 
436

 
515

 
1,070

Total Revenues
 
9,151

 
10,486

 
18,088

Costs and Expenses
 
 
 
 
 
 
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

 
296

Impairment charge and other matters (Notes 2 and 6)
 
(170
)
 
162

 
258

Total Costs and Expenses
 
8,336

 
9,956

 
17,721

Operating Income
 
815

 
530

 
367

Interest cost to affiliates, net (Note 4)
 
2

 
—

 
1

Other interest cost and debt expense, net
 
(270
)
 
(210
)
 
(146
)
Capitalized interest
 
111

 
76

 
78

Gain on investment in affiliate (Note 3)
 
41

 
—

 
—

Other income
 
37

 
22

 
25

Income Before Provision for Income Taxes
 
736

 
418

 
325

Provision for income taxes (Note 2)
 
(27
)
 
(21
)
 
(25
)
Net Income
 
709

 
397

 
300

Net income attributable to noncontrolling interests
 
(3
)
 
(3
)
 
(9
)
Net income attributable to redeemable noncontrolling interests (Note 3)
 
(1
)
 
(1
)
 
—

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

 
$
393

 
$
291

 
 
 
 
 
 
 
Calculation of Limited Partners' interest:
 
 
 
 
 
 
Net Income attributable to Sunoco Logistics Partners L.P.
 
$
705

 
$
393

 
$
291

Less: General Partner's interest
 
(393
)
 
(288
)
 
(181
)
Limited Partners' interest
 
$
312

 
$
105

 
$
110

 
 
 
 
 
 
 
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit (Note 5):
 
 
 
 
 
 
Basic
 
$
0.98

 
$
0.42

 
$
0.52

Diluted
 
$
0.98

 
$
0.42

 
$
0.51

 
 
 
 
 
 
 
Weighted average Limited Partners' units outstanding (Note 5):
 
 
 
 
 
 
Basic
 
304.5

 
250.9

 
212.9

Diluted
 
305.4

 
251.7

 
214.1

 
 
 
 
 
 
 
Net Income
 
$
709

 
$
397

 
$
300

Adjustment to affiliate's pension funded status
 
—

 
(1
)
 
1

Other Comprehensive Income (Loss)
 
—

 
(1
)
 
1

Comprehensive Income
 
709

 
396

 
301

Less: Comprehensive income attributable to noncontrolling interests
 
(3
)
 
(3
)
 
(9
)
Less: Comprehensive income attributable to redeemable noncontrolling interests
 
(1
)
 
(1
)
 
—

Comprehensive Income attributable to Sunoco Logistics Partners L.P.
 
$
705

 
$
392

 
$
292



            
(See Accompanying Notes)



74


SUNOCO LOGISTICS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
 
December 31,
 
 
2016
 
2015
Assets
 
 
 
 
Cash and cash equivalents
 
$
41

 
$
37

Accounts receivable, net
 
1,555

 
1,165

Accounts receivable, affiliated companies (Note 4)
 
44

 
20

Inventories (Note 6)
 
934

 
607

Note receivable, affiliated companies (Note 4)
 
301

 
—

Other current assets
 
31

 
19

Total Current Assets
 
2,906

 
1,848

Properties, plants and equipment
 
13,551

 
11,527

Less accumulated depreciation and amortization
 
(1,227
)
 
(835
)
Properties, plants and equipment, net (Note 7)
 
12,324

 
10,692

Investment in affiliates (Note 8)
 
952

 
802

Goodwill (Note 9)
 
1,609

 
1,358

Intangible assets, net (Note 9)
 
977

 
718

Other assets
 
81

 
71

Total Assets
 
$
18,849

 
$
15,489

Liabilities and Equity
 
 
 
 
Accounts payable
 
$
1,750

 
$
1,251

Accounts payable, affiliated companies (Note 4)
 
63

 
39

Accrued liabilities
 
287

 
329

Accrued taxes payable (Note 2)
 
38

 
44

Total Current Liabilities
 
2,138

 
1,663

Long-term debt (Note 10)
 
7,313

 
5,591

Other deferred credits and liabilities
 
133

 
125

Deferred income taxes (Note 2)
 
257

 
254

Total Liabilities
 
9,841

 
7,633

Commitments and contingent liabilities (Note 11)
 


 

Redeemable noncontrolling interests (Note 3)
 
15

 
15

Redeemable Limited Partners' interests (9,416,196 Class B units outstanding at
     December 31, 2016 and 2015) (Note 4)
 
300

 
286

Equity
 
 
 
 
Sunoco Logistics Partners L.P. equity
 
 
 
 
Limited Partners' interests (322,382,267 and 268,849,818 units outstanding at December 31, 2016 and 2015, respectively)
 
7,700

 
6,577

General Partner's interest
 
960

 
944

Total Sunoco Logistics Partners L.P. equity
 
8,660

 
7,521

Noncontrolling interests
 
33

 
34

Total Equity
 
8,693

 
7,555

Total Liabilities and Equity
 
$
18,849

 
$
15,489


(See Accompanying Notes)

75


SUNOCO LOGISTICS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
Cash Flows from Operating Activities:
 
 
 
 
 
 
Net Income
 
$
709

 
$
397

 
$
300

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
 
Depreciation and amortization expense
 
446

 
382

 
296

Impairment charge and other matters
 
(170
)
 
162

 
258

Gain on investment in affiliate (Note 3)
 
(41
)
 
—

 
—

Deferred income tax expense (benefit)
 
3

 
5

 
(4
)
Amortization of bond premium
 
(9
)
 
(13
)
 
(14
)
Non-cash compensation expense (Note 14)
 
23

 
17

 
16

Equity in earnings of unconsolidated affiliates
 
(39
)
 
(24
)
 
(25
)
Distributions from unconsolidated affiliates
 
25

 
23

 
14

Changes in working capital pertaining to operating activities:
 
 
 
 
 
 
Accounts receivable, net
 
(397
)
 
602

 
445

Accounts receivable, affiliated companies
 
(22
)
 
(11
)
 
4

Inventories
 
(149
)
 
(299
)
 
(105
)
Accounts payable and accrued liabilities
 
466

 
(667
)
 
(570
)
Accounts payable, affiliated companies
 
23

 
18

 
4

Accrued taxes payable
 
(6
)
 
(8
)
 
(19
)
Unrealized (gains) losses on commodity risk management activities
 
39

 
4

 
(17
)
Other
 
(13
)
 
10

 
(17
)
Net cash provided by operating activities
 
888

 
598

 
566

Cash Flows from Investing Activities:
 
 
 
 
 
 
Capital expenditures
 
(1,949
)
 
(2,706
)
 
(2,416
)
Acquisitions (Notes 3 and 8)
 
(786
)
 
(131
)
 
(433
)
Change in note receivable, affiliated companies
 
(301
)
 
—

 
—

Change in long-term note receivable
 
(2
)
 
(17
)
 
(17
)
Net cash used in investing activities
 
(3,038
)
 
(2,854
)
 
(2,866
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
Distributions paid to limited and general partners
 
(961
)
 
(686
)
 
(468
)
Distributions paid to noncontrolling interests
 
(5
)
 
(3
)
 
(4
)
Contributions from general partner
 
—

 
—

 
2

Net proceeds from issuance of limited partner units
 
1,388

 
1,519

 
839

Payments of statutory withholding on net issuance of limited partner units under LTIP
 
(4
)
 
(11
)
 
(9
)
Repayments under credit facilities
 
(5,840
)
 
(3,662
)
 
(2,845
)
Borrowings under credit facilities
 
7,200

 
4,039

 
2,795

Net proceeds from issuance of long-term debt
 
544

 
991

 
1,976

Repayments of senior notes
 
(175
)
 
—

 
(175
)
Advances to affiliated companies, net
 
—

 
—

 
239

Contributions attributable to acquisition from affiliate
 
7

 
11

 
12

Other
 
—

 
(6
)
 
—

Net cash provided by financing activities
 
2,154

 
2,192

 
2,362

Net change in cash and cash equivalents
 
4

 
(64
)
 
62

Cash and cash equivalents at beginning of period
 
37

 
101

 
39

Cash and cash equivalents at end of period
 
$
41

 
$
37

 
$
101



(See Accompanying Notes)

76


SUNOCO LOGISTICS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF EQUITY
(in millions)
 
 
 
Limited Partners
 
General
Partner
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
 
 
Units
 
$
 
$
 
$
 
$
 
$
Balance at December 31, 2013
 
207.7

 
$
5,292

 
$
912

 
$
—

 
$
121

 
$
6,325

Net Income
 
—

 
$
110

 
$
181

 
$
—

 
$
9

 
$
300

Adjustment to affiliate's pension funded status
 
—

 
—

 
—

 
1

 
—

 
1

Total comprehensive income
 
—

 
110

 
181

 
1

 
9

 
301

Issuance of limited partner units to the public
 
18.0

 
839

 
2

 
—

 
—

 
841

Non-cash compensation expense
 
0.4

 
16

 
—

 
—

 
—

 
16

Distribution equivalent rights
 
—

 
(4
)
 
—

 
—

 
—

 
(4
)
Payment of statutory withholding on issuance under LTIP
 
—

 
(9
)
 
—

 
—

 
—

 
(9
)
Distributions
 
—

 
(302
)
 
(166
)
 
—

 
(4
)
 
(472
)
Contributions attributable to acquisition from affiliate
 
—

 
12

 
—

 
—

 
—

 
12

Increase attributable to common control acquisition
 
—

 
53

 
1

 
—

 
—

 
54

Acquisition of noncontrolling interest in a consolidated subsidiary
 
—

 
(254
)
 
(5
)
 
—

 
(66
)
 
(325
)
Other
 
—

 
(1
)
 
—

 
—

 
—

 
(1
)
Balance at December 31, 2014
 
226.1

 
$
5,752

 
$
925

 
$
1

 
$
60

 
$
6,738

Net Income
 
—

 
$
105

 
$
288

 
$
—

 
$
3

 
$
396

Adjustment to affiliate's pension funded status
 
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Total comprehensive income (loss)
 
—

 
105

 
288

 
(1
)
 
3

 
395

Issuance of limited partner units to the public
 
42.3

 
1,519

 
—

 
—

 
—

 
1,519

Non-cash compensation expense
 
0.4

 
17

 
—

 
—

 
—

 
17

Distribution equivalent rights
 
—

 
(2
)
 
—

 
—

 
—

 
(2
)
Payment of statutory withholding on issuance under LTIP
 
—

 
(11
)
 
—

 
—

 
—

 
(11
)
Distributions
 
—

 
(425
)
 
(261
)
 
—

 
(3
)
 
(689
)
Contributions attributable to acquisition from affiliate
 
—

 
11

 
—

 
—

 
—

 
11

Acquisition of noncontrolling interest in a consolidated subsidiary
 
—

 
(103
)
 
(2
)
 
—

 
(26
)
 
(131
)
Decrease attributable to issuance of Class B units (Note 4)
 
—

 
(287
)
 
(5
)
 
—

 
—

 
(292
)
Other
 
—

 
1

 
(1
)
 
—

 
—

 
—

Balance at December 31, 2015
 
268.8

 
$
6,577

 
$
944

 
$
—

 
$
34

 
$
7,555

Net Income
 
—

 
$
312

 
$
393

 
$
—

 
$
3

 
$
708

Total comprehensive income
 
—

 
312

 
393

 
—

 
3

 
708

Issuance of limited partner units to the public
 
53.3

 
1,388

 
—

 
—

 
—

 
1,388

Non-cash compensation expense
 
0.3

 
23

 
—

 
—

 
—

 
23

Distribution equivalent rights
 
—

 
(5
)
 
—

 
—

 
—

 
(5
)
Payment of statutory withholding on issuance under LTIP
 
—

 
(4
)
 
—

 
—

 
—

 
(4
)
Distributions
 
—

 
(584
)
 
(377
)
 
—

 
(4
)
 
(965
)
Contributions attributable to acquisition from affiliate
 
—

 
7

 
—

 
—

 
—

 
7

Decrease attributable to issuance of Class B units (Note 4)
 
—

 
(14
)
 
—

 
—

 
—

 
(14
)
Balance at December 31, 2016
 
322.4

 
$
7,700

 
$
960

 
$
—

 
$
33

 
$
8,693


(See Accompanying Notes)

77


SUNOCO LOGISTICS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
Sunoco Logistics Partners L.P. (the "Partnership" or "SXL") is a publicly traded Delaware limited partnership that owns and 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. The Partnership conducts its business activities in 37 states located throughout the United States. Sunoco Partners LLC, a Pennsylvania limited liability company and the general partner of the Partnership, is a consolidated subsidiary of Energy Transfer Partners, L.P. ("ETP"), a publicly traded Delaware limited partnership.
On November 20, 2016, SXL and its 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, the 364-Day credit facility is expected to be terminated and repaid in connection with the Merger. At the effective 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.

2. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements reflect the results of the Partnership and its wholly-owned subsidiaries, including Sunoco Logistics Partners Operations L.P. (the "Operating Partnership"), the proportionate shares of the Partnership's undivided interests in assets, and the accounts of entities in which the Partnership has a controlling financial interest. A controlling financial interest is evidenced by either a voting interest greater than 50 percent or a risk and rewards model that identifies the Partnership or one of its subsidiaries as the primary beneficiary of a variable interest entity. The Partnership currently holds a controlling financial interest in Inland Corporation ("Inland"), Mid-Valley Pipeline Company ("Mid-Valley"), Price River Terminal, LLC ("PRT"), and, effective February 1, 2017, Permian Express Partners LLC ("PEP"), which is a joint venture with ExxonMobil. These entities are reflected as consolidated subsidiaries of the Partnership. Effective November 1, 2016, SunVit Pipeline LLC ("SunVit") became a wholly-owned subsidiary of the Partnership in connection with the acquisition from Vitol Inc. The Partnership is not the primary beneficiary of any variable-interest entities ("VIEs"). All significant intercompany accounts and transactions are eliminated in consolidation and noncontrolling interests in net income and equity are shown separately in the consolidated statements of comprehensive income and balance sheets. Equity ownership interests in joint ventures in which the Partnership does not have a controlling financial interest, but over which the Partnership can exercise significant influence, are accounted for under the equity method of accounting.

78


Use of Estimates
The preparation of financial statements in conformity with United States generally accepted accounting principles ("GAAP") requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements and accompanying notes. Actual amounts could differ from these estimates.
Reclassification
Certain amounts in the prior years' consolidated financial statements have been reclassified to conform to the current year presentation. The changes did not impact reported net income for any periods presented.
New Accounting Pronouncements
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, which created Topic 842, Leases, and will supersede the requirements in Topic 840. The objective of ASU 2016-02 is to establish the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership is currently evaluating the impact that it will have on its consolidated financial statements and related disclosures.
In May 2014, the FASB codified guidance in ASU 2014-09 related to the recognition of revenue from contracts with customers, and has since released associated clarifying guidance in subsequent periods. The new standards outline the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration which the entity expects to be entitled in exchange for those goods or services. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within those reporting periods, with early adoption permitted. The Partnership expects to adopt ASU 2014-09 in the first quarter of 2018 and will apply the cumulative catchup transition method.
The Partnership is in the process of evaluating its revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in the evaluation process, it has been determined that the timing and/or amount of revenue recognized on certain contracts will be impacted by the adoption of the new standard; however, the process of quantifying these impacts is ongoing and an assessment of materiality in relation to the financial statements has not yet been determined. In addition, the Partnership is in the process of implementing appropriate changes to its business processes, systems and controls to support recognition and disclosure under the new standard. The Partnership will continue to monitor for additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing conclusions on specific interpretative issues to other peers in the industry, to the extent that such information is available.
Revenue Recognition
Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Acquisition and marketing revenues for crude oil, NGLs and refined products are recognized when title to and risk of loss of the product is transferred to the customer. Terminalling and storage revenues are recognized at the time the services are provided. Revenues are not recognized for exchange transactions, which are entered into primarily to acquire a commodity of a desired quality or to reduce transportation costs by taking delivery closer to the Partnership's end markets. Any net differential for exchange transactions is recorded as an adjustment to cost of products sold in the consolidated statements of comprehensive income.
Affiliated revenues are generated from sales of crude oil, NGLs and refined products, as well as pipeline transportation, terminalling and storage services to ETP and its affiliates. Sales of crude oil, NGLs and refined products to affiliated entities are priced using market-based rates. Affiliated entities pay fees for transportation or terminalling services based on the terms and conditions of established agreements or published tariffs.
Cash Equivalents
The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. At December 31, 2016 and 2015, cash equivalents consisted of time deposits and money market investments.
Accounts Receivable, Net
Accounts receivable represent valid claims against non-affiliated customers (see Note 4 for affiliated receivables) for products sold or services rendered. The Partnership extends credit terms to certain customers after review of various credit indicators, including the customers' credit ratings. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management's expectations regarding collectability. Actual receivable balances are charged against the reserve when all collection efforts have been exhausted.

79


Inventories
Inventories are valued at the lower of cost or market. Crude oil, NGLs and refined products inventory costs have been determined using the last-in, first-out method ("LIFO"). Under this methodology, the cost of products sold consists of the actual acquisition costs of the Partnership, which include transportation and storage costs. Such costs are adjusted to reflect increases or decreases in inventory quantities, which are valued based on the changes in the LIFO inventory layers. The cost of materials, supplies and other inventories is principally determined using the average-cost method.
During the periods ended December 31, 2016, 2015 and 2014, a lower of cost or market ("LCM") adjustment was applied, as necessary, to the Partnership's crude oil, NGLs and refined products inventories due to changes in commodity prices. Adjustments are calculated based upon current replacement costs.
See Notes 6 and 18 for additional information on the LCM reserves and their impact to the Partnership's net income.
Properties, Plants and Equipment
Properties, plants and equipment are stated at cost. Additions to properties, plants and equipment, including replacements and improvements, are recorded at cost. Repair and maintenance expenditures are charged to expense as incurred. Depreciation is determined principally using the straight-line method based on the estimated useful lives of the related assets. For certain interstate pipelines, the depreciation rate is applied to the net asset value based on the Federal Energy Regulatory Commission's ("FERC") requirements, which approximates the estimated useful lives of the related assets.
Capitalized Interest
The Partnership capitalizes interest incurred on funds borrowed for certain capital projects and contributions to joint venture interests during periods in which construction activities are in progress to bring those projects to their intended use.
Investment in Affiliates
Investment in affiliates, which consist of joint ventures in which the Partnership does not have a controlling financial interest, but over which the Partnership can exercise significant influence, are accounted for under the equity method of accounting. Under this method, an investment is carried at cost, adjusted for the equity in income (loss), reduced for dividends received and adjusted for changes in accumulated other comprehensive income (loss). Income recognized from the Partnership's joint venture interests is presented within other income in the consolidated statements of comprehensive income.
The Partnership allocates the excess of its investment cost over its equity in the net assets of affiliates to the underlying tangible and intangible assets of the joint ventures. Other than land and indefinite-lived intangible assets, all amounts allocated, principally to pipeline and related assets, are amortized using the straight-line method over their estimated useful life of 40 years. The amortization of these amounts is also presented within other income in the consolidated statements of comprehensive income.
Acquisitions
The Partnership records third-party business combinations at their estimated fair values as of the date of acquisition. Any excess of consideration transferred plus the fair value of noncontrolling interest over the estimated fair value of the net assets acquired is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeds the purchase price plus the fair value of the noncontrolling interest, a gain is recorded in results of current operations. The results of operations of acquired businesses are included in the Partnership's results from the dates of acquisition.
Assets acquired and liabilities assumed include tangible and intangible assets, and contingent assets and liabilities. The estimated fair values of these assets and liabilities are determined based on observable inputs such as quoted market prices, information from comparable transactions, offers made by other prospective acquirers in the cases where the Partnership has certain rights to acquire additional interests in existing investments, and the replacement cost of assets in the same condition or stage of usefulness; or on unobservable inputs such as expected future cash flows or internally developed estimates of value. The Partnership's fair value measurements are classified within the fair value hierarchy established by GAAP based on the lowest level (least observable) input that is significant to the measurement in its entirety.
Assets acquired and liabilities assumed in connection with acquisitions from entities under common control are recorded by the Partnership at the common control entity's net carrying value. The Partnership records any difference between the consideration paid and the carrying value of the net assets and liabilities as a distribution from, or contribution to, redeemable limited partner interests or equity, as applicable.
The Partnership's asset acquisitions are recorded at the purchase price, which is allocated to the acquired assets and assumed liabilities based on their relative estimated fair values.
See Note 3 for additional information concerning the Partnership's recent acquisitions.

80


Impairment of Long-Lived Assets
Long-lived assets, other than those held for sale, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. An asset is considered to be impaired when the undiscounted estimated net cash flows expected to be generated by the asset are less than its carrying amount. The impairment recognized is the amount by which the carrying amount exceeds the estimated fair value of the impaired asset. Long-lived assets held for sale are recorded at the lower of their carrying amount or estimated fair value less cost to sell the assets.
Goodwill
Goodwill, which represents the excess of the purchase price in a business combination over the fair value of net assets acquired, is tested for impairment annually in the fourth quarter, or more often if events or changes in circumstances indicate that the carrying value of goodwill may exceed its estimated fair value. The Partnership's general partner was acquired and became a consolidated subsidiary of ETP in the fourth quarter 2012. In connection with the acquisition, the Partnership elected to apply "push-down accounting" which required the Partnership's assets and liabilities to be adjusted to fair value on the closing date of the acquisition, which included an increase to the Partnership's goodwill balance of approximately $1.3 billion.
Management's process for evaluating goodwill for impairment involves estimating the fair value of the Partnership's reporting units that include goodwill. Inherent in estimating fair value for each reporting unit are certain judgments and estimates relating the market multiples for comparable businesses, management's interpretation of current economic indicators, and market conditions and assumptions about the Partnership's strategic plans with regards to its operations. To the extent additional information arises, market conditions change or the Partnership's strategies change, it is possible the conclusion regarding whether the goodwill is impaired could change and result in future goodwill impairment charges.
During the fourth quarter 2015, the Partnership realigned its reporting segments and, in accordance with accounting guidance, was required to test its goodwill balance for impairment both before and after the change in its reportable segments. Due to volatility within the energy markets, the Partnership utilized the assistance of a third party valuation firm to develop models to estimate the fair value of each of its reporting units that contain goodwill. The fair value of the reporting units was estimated using a combination of discounted cash flow and market multiple methodologies. Under the discounted cash flow methodology, fair value was estimated using the present value of Management's projected cash flows for each reporting unit which was calculated using the expected return a market participant would require for each reporting unit. Under the market multiple methodology, a selection of peer group companies, which are similar from an operational or industry perspective, were considered in estimating market multiples. These multiples were applied to Management's projected Adjusted EBITDA in order to estimate fair value. For the 2015 impairment test, the fair value of the Partnership's legacy Crude Oil Acquisition and Marketing segment was determined to be approximately 3 percent less than its carrying value. In accordance with accounting guidance, a second test was performed to estimate the fair value of the reporting unit's assets and liabilities, which included determining an implied goodwill value. The Partnership performed the second test and determined that the implied fair value of the Crude Oil Acquisition and Marketing segment's goodwill exceeded its current carrying value.
See Note 9 for additional information on the Partnership's goodwill balance.
Intangible Assets
The Partnership has acquired intangible assets, such as customer relationships and patents related to butane blending technology. The value assigned to these intangible assets is amortized on a straight-line basis over their respective economic lives through depreciation and amortization expense in the consolidated statements of comprehensive income.
Environmental Remediation
The Partnership accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point or points in the range are more likely, in which case the most likely amount in this range is accrued.





81


Income Taxes
The Partnership is not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose income taxes. Rather, income taxes are generally assessed at the partner level. There are some states in which the Partnership operates where it is subject to state and local income taxes. Substantially all of the income tax amounts reflected in the Partnership's consolidated financial statements are related to the operations of Inland, Mid-Valley and West Texas Gulf Pipe Line Company ("West Texas Gulf"), all of which are subject to income taxes for federal and state purposes at the corporate level. The effective tax rates for these entities approximate the federal statutory rate of 35 percent.
The Partnership recognizes a tax benefit from uncertain positions only if it is more likely than not that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authorities' widely understood administrative practices and precedents. The tax benefits recognized from such positions are measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon settlement.
The following table presents the components of income tax expense for the periods presented:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Federal
 
 
 
 
 
 
Current
 
$
22

 
$
15

 
$
24

Deferred
 
2

 
6

 
(5
)
State
 
 
 
 
 
 
Current
 
4

 
—

 
6

Deferred
 
(1
)
 
—

 
—

Total income tax expense
 
$
27

 
$
21

 
$
25

The income taxes paid by Inland, Mid-Valley, and West Texas Gulf approximated current income tax expense for each year presented.
In taxable jurisdictions, the Partnership records deferred income taxes on all significant temporary differences between the book basis and the tax basis of assets and liabilities. At December 31, 2016 and 2015, the Partnership had $257 and $254 million, respectively, of net deferred tax liability derived principally from the difference in the book and tax bases of properties, plants and equipment associated with Inland, Mid-Valley, and West Texas Gulf.
Long-Term Incentive Plan
The Partnership accounts for the compensation cost associated with all unit-based payment awards at grant-date fair value and reports the related expense within operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income. Unit-based compensation cost for all outstanding awards of restricted units is based on the grant date market price of the underlying unit. The Partnership recognizes unit-based compensation expense on a straight-line basis over the requisite service period. In accordance with the terms of certain awards, the recognition of compensation expense is accelerated for participants who become retirement-eligible during the applicable vesting period.
Asset Retirement Obligations
Asset retirement obligations ("AROs") represent the fair value of expected liabilities related to the future retirement of long-lived assets and are recorded at the time in which a legal obligation is incurred. A corresponding asset is recorded concurrently and is depreciated over the anticipated active life of the related long-lived asset. The value of the ARO is determined based on estimates and assumptions regarding ongoing maintenance and repair, asset repurposing costs, disposal costs and associated contractual obligations related to the Partnership's pipelines, terminal facilities, storage tanks, truck and leased assets. The Partnership bases these estimates on historical and budgeted costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be level 3 measurements, as they are based on both observable and unobservable inputs.
The Partnership's consolidated balance sheets include AROs as a component of other deferred credits and liabilities of $88 million at December 31, 2016 and 2015. The Partnership believes it may have additional asset retirement obligations related to its pipeline assets and storage tanks for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.


82


Fair Value Measurements
The Partnership determines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Partnership utilizes valuation techniques that maximize the use of observable inputs (levels 1 and 2) and minimize the use of unobservable inputs (level 3) within the fair value hierarchy established by the FASB. Where quoted pricing is not available, the Partnership utilizes a "market" or "income" approach to determine fair value. This method uses pricing and other information related to market transactions for identical or comparable assets and liabilities. Assets and liabilities are classified within the fair value hierarchy based on the lowest level (least observable) input that is significant to the measurement in its entirety.
Lease Accounting
The Partnership accounts for arrangements that convey the right to use property, plant or equipment for a stated period of time as leases. Whether an arrangement contains a lease is determined at inception of the arrangement based on all of the facts and circumstances. The Partnership reassesses whether an arrangement contains a lease after the inception of the arrangement only if (a) there is a change in the contractual terms, (b) a renewal option is exercised or an extension is agreed to by the parties to the arrangement, (c) there is a change in the determination of whether or not fulfillment is dependent on specified property, plant, or equipment, or (d) there is a substantial physical change to the specified property, plant, or equipment. The Partnership continually analyzes its new and existing arrangements to evaluate whether they contain leases. Revenue or expense from arrangements where the Partnership is the lessor or lessee, respectively, is recognized ratably over the term of the underlying arrangement.
Net Income Attributable to Sunoco Logistics Partners L.P. per Limited Partner Unit
The Partnership uses the two-class method to determine basic and diluted earnings per unit. The two-class method is an earnings allocation formula that determines the earnings for each class of equity ownership and participating security according to distributions declared and participation rights in undistributed earnings. The Partnership calculates basic and diluted net income attributable to Sunoco Logistics Partners L.P. ("net income attributable to SXL") per limited partner unit by dividing net income attributable to SXL, after deducting the amounts allocated to the general partner's interest and incentive distribution rights ("IDRs"), by the weighted average number of limited partner units and Class B units outstanding during the period. IDRs in a master limited partnership are treated as participating securities for the purpose of computing net income attributable to limited partner units. The general partner holds all of the IDRs. In addition, when earnings differ from cash distributions, undistributed or over distributed earnings are to be allocated to the general partner, limited partners and Class B unitholders based on the contractual terms of the partnership agreement. See Note 4 for additional information on the terms of the Class B units.

3. Acquisitions
A key component of the Partnership's primary business strategy is to pursue strategic and accretive acquisitions that complement its existing asset base. The Partnership completed the following acquisitions during the years ended December 31, 2016, 2015 and 2014:
•
In November 2016, the Partnership completed an acquisition from Vitol Inc. ("Vitol") of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides the Partnership 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 resulted in the entity becoming a wholly-owned subsidiary of the Partnership. SunVit, which was renamed Permian Express Terminal LLC ("PET") in the fourth quarter 2016, connects the Midland terminal to the Partnership's Permian Express 2 pipeline, a key takeaway to bring Permian crude oil to multiple markets. The acquisition is included in the Crude Oil segment.
The $769 million purchase price, net of cash received, consisted primarily of the following preliminary fair value allocations: net working capital ($13 million) largely attributable to inventory and receivables; properties, plants and equipment ($286 million) primarily related to pipeline and terminalling assets; intangible assets ($313 million) attributable to customer relationships; and an increase to goodwill ($251 million). The consolidation of SunVit resulted in a $41 million gain which represented the difference between the carrying value of the Partnership's previously held equity interest and the fair value on the date of acquisition.

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•
In August 2016 and March 2014, the Partnership acquired additional ownership interests in the Explorer Pipeline Company ("Explorer") for $17 and $42 million, respectively, which increased the total ownership interest from 9.4 to 15.0 percent. The equity-method investment continues to be reported within the Refined Products segment.
•
In December 2014, the Partnership acquired an additional 28.3 percent ownership interest in West Texas Gulf from Chevron Pipe Line Company for $325 million, increasing the Partnership's controlling financial interest to 88.6 percent. In January 2015, the Partnership acquired the remaining noncontrolling ownership interest in West Texas Gulf for $131 million. As these transactions represented the acquisition of ownership interest in a consolidated subsidiary, noncontrolling interest and partners' equity were reduced by $92 and $364 million, respectively, in accordance with applicable accounting guidance. West Texas Gulf is reflected as a consolidated subsidiary within the Crude Oil segment.
•
In the second quarter 2014, the Partnership 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 below). The acquisition is included in the Crude Oil segment.
•
In the second quarter 2014, the Partnership acquired a 55 percent economic and voting interest in 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 and is included in the Crude Oil segment. 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. As a result, the noncontrolling interests attributable to PRT are excluded from the Partnership's total equity and are instead reflected as redeemable interests in the consolidated balance sheet.
The $65 million purchase price for the EDF and PRT acquisitions (net of cash received) consisted primarily of net working capital largely attributable to inventory ($24 million), properties, plants and equipment ($14 million), and intangible assets ($28 million). These fair value allocations also resulted in an increase to goodwill ($12 million) and redeemable noncontrolling interests ($15 million).
No pro forma information has been presented as the impact of the acquisitions during 2016, 2015 and 2014 was not material in relation to the Partnership's consolidated results of operations or financial position.

4. Related Party Transactions
Acquisition of Sunoco
The Partnership has various operating and administrative agreements with ETP and its affiliates, including the agreements described below. ETP and its affiliates perform the administrative functions defined in such agreements on the Partnership's behalf.
Service and Commodity Sales Agreements
The Partnership is party to various agreements with ETP and its affiliates to provide pipeline, terminalling and storage services, in addition to agreements for the purchase and sale of crude oil, NGLs and refined products. This activity is reflected in affiliated revenues in the consolidated statements of comprehensive income.
The Partnership is party to the following commercial agreements with its affiliated entities:
•
Pipeline Operator Agreement: The Partnership has agreements with certain of its joint venture interests to serve as operators of their respective pipeline systems. The agreements include a specified management fee and have either a defined termination date or are able to be terminated by both parties in certain cases.
•
Refined Products Terminal Services Agreement: The Partnership has a five-year refined products terminal services agreement with Sunoco under which Sunoco may throughput refined products at the Partnership's terminals. The agreement contains no minimum throughput obligations for Sunoco. The agreement runs through February 2017.
•
Fort Mifflin Terminal Services Agreement: The Partnership has an agreement with Philadelphia Energy Solutions ("PES") relating to the Fort Mifflin terminal complex. Under this agreement, PES will deliver an average of 300 thousand barrels per day of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin terminal complex; however, the Partnership is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. The Partnership executed the ten-year agreement with PES in September 2012. The Partnership had a previous agreement with Sunoco, with terms similar to those contained in the agreement with PES.

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These agreements also provide PES with the option to purchase the Fort Mifflin and Belmont terminals if certain triggering events occur, including a sale of substantially all of the assets or operations of the Philadelphia refinery, an initial public offering, or a public debt filing of more than $200 million. The purchase price for each facility would be established based on a fair value amount determined by designated third parties.
•
Inter-Refinery Pipeline Lease: In September 2012, Sunoco assigned its lease for the use of the Partnership's inter-refinery pipelines between the Philadelphia refinery and the Marcus Hook Industrial Complex to PES. Under the twenty-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67 percent each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse the Partnership for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during the years 2014 through 2016.
•
Marcus Hook Industrial Complex Storage and Terminalling Services: In connection with the 2013 acquisition of the Marcus Hook Industrial Complex, the Partnership assumed an agreement to provide butane storage and terminal services to PES at the facility. The 10 year agreement extends through September 2022.
•
Refined Products Storage Agreements: The Partnership has agreements with an affiliated entity to utilize storage services at the Mont Belvieu, Texas and Hattiesburg, Mississippi terminal locations. The agreements run through November 2018.
•
Purchase and Sale Agreements: The Partnership has agreements for the purchase and sale of crude oil, NGLs and refined products with affiliated entities. These agreements are negotiated at market-based rates, do not extend beyond 2017, and can be terminated by either party in certain cases.
•
Terminalling Services: The Partnership has agreements with affiliates for the use of its terminal assets, as well as its use of an affiliated terminal asset to facilitate the Partnership's acquisition and marketing activities. The agreements are based on market terms and negotiated based on the respective term. These agreements vary in duration and can be terminated by either party in certain cases.
•
Pipeline Agreements: The Partnership has agreements with affiliated parties to utilize its pipelines to supply their business needs. All pipeline movements are on the same terms that would be available to unaffiliated customers under similar terms and are based on published tariff rates on the respective pipeline.
Advances to/from Affiliate
The Partnership previously participated in Sunoco's centralized cash management program pursuant to a treasury services agreement. Under the program, the Partnership's cash receipts and cash disbursements were processed, together with those of Sunoco and its other subsidiaries, through Sunoco's cash accounts with a corresponding credit or charge to an affiliated account. The Partnership established separate cash accounts in the fourth quarter 2013, and ceased participation in Sunoco's cash management program in 2014.
Administrative Services
The Partnership has no employees. The operations of the Partnership are carried out by employees of the general partner. The Partnership reimburses the general partner and its affiliates for certain costs and other direct expenses incurred on the Partnership's behalf. These costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of services received by the Partnership. Additional general and administrative costs incurred are paid directly by the Partnership.
Under the Omnibus Agreement, the Partnership pays ETP an annual administrative fee that includes expenses incurred by ETP and its affiliates to perform certain centralized corporate functions, such as legal, accounting, engineering, information technology, insurance, utilities expense, office space rental, and other corporate services, including the administration of employee benefit plans. The costs may be increased if the acquisition or construction of new assets or businesses requires an increase in the level of general and administrative services received by the Partnership. These fees do not include the costs of shared insurance programs (which are allocated to the Partnership based upon its share of the cash premiums incurred), the salaries of pipeline and terminal personnel or other employees of the general partner, or the cost of their employee benefits. The amounts incurred in connection with the centralized corporate functions and shared insurance costs were not material to the Partnership's results of operations during the three year period ended December 31, 2016.




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The Partnership participates in various employee benefit plans with ETP and its affiliates, including employee and retiree medical, dental and life insurance plans, defined contribution 401(k) plans, incentive compensation plans and other such benefits. The total expense of benefit plan participation was $61, $54, and $45 million for the years ended December 31, 2016, 2015 and 2014, respectively. These expenses are reflected in operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income.
Affiliated Revenues and Accounts Receivable, Affiliated Companies
The Partnership is party to various agreements with ETP and its affiliates to supply crude oil, NGLs and refined products, as well as to provide pipeline and terminalling services. Affiliated revenues in the consolidated statements of comprehensive income consist of revenues from ETP and its affiliated entities related to sales of crude oil, NGLs and refined products, and services, including pipeline transportation, terminalling, storage and blending.
Note Receivable, Affiliated Companies
See Note 8 for additional information related to the note receivable in connection with the Bakken Pipeline project.
Investments in Affiliates
See Note 8 for additional information related to the Partnership's participation in the Bayou Bridge and Bakken pipeline projects.
Issuance of Redeemable Limited Partners' Interests    
In October 2015, the Partnership issued 9.4 million Class B units to ETP in conjunction with the purchase of a 30 percent ownership interest in the Bakken pipeline. The Class B units represent a new class of limited partner interests in the Partnership which 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. The Class B units will automatically convert to common units on a one-for-one basis in the third quarter 2017. ETP can exercise a put right during the third quarter 2017, effective prior to the one-for-one conversion date, for the greater of $313.5 million or the fair market value of the units, as defined in the unitholder agreement. As a result of the available put option, the amount attributable to the Class B units is excluded from total equity and instead reflected as redeemable interests in the Partnership's consolidated balance sheet. However, the Class B units will be retired without exercise if the Merger is approved (see Note 1 for additional information).
Contributions Attributable to Acquisition from Affiliate
In the fourth quarter 2014, the Partnership acquired land at Eagle Point from Sunoco under a purchase option embedded in an existing lease. As a transaction between entities under common control, the land was recorded at Sunoco's historical carrying value, resulting in an increase to equity of $54 million.
Capital Contributions
In July 2014, the Partnership agreement was amended to remove the obligation of the general partner to make capital contributions upon the issuance of limited partner units to retain a two percent interest. Prior to this amendment, the general partner contributed $2 million primarily related to the Partnership's issuance of limited partner units under its at-the-market equity offering program ("ATM" program) in 2014. The general partner did not make any capital contributions to the Partnership in 2015 or 2016.

5. Net Income Attributable to Sunoco Logistics Partners L.P. per Limited Partner Unit
The general partner's interest in net income attributable to SXL consists of its general partner interest and "incentive distributions," which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.0833 per limited partner unit (Note 13). The general partner was allocated net income attributable to SXL of $393 million (representing 56 percent of total net income attributable to SXL) for the year ended December 31, 2016; $288 million (representing 73 percent of total net income attributable to SXL) for the year ended December 31, 2015; $181 million (representing 62 percent of total net income attributable to SXL) for the year ended December 31, 2014. Diluted net income attributable to SXL per limited partner unit is calculated by dividing the limited partners' interest in net income attributable to SXL by the sum of the weighted average number of limited partner and Class B units outstanding, and the dilutive effect of incentive unit awards (Note 14).
For the year ended December 31, 2016, net income attributable to SXL was reduced by $14 million in determining earnings per limited partner unit as a result of the Class B units, which are reflected as redeemable limited partner interests in the consolidated balance sheet.

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The following table sets forth the reconciliation of the weighted average number of limited partner and Class B units used to compute basic net income attributable to SXL per limited partner unit to those used to compute diluted net income attributable to SXL per limited partner unit for the periods presented:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Weighted average number of units outstanding—basic
 
304.5

 
250.9

 
212.9

Add effect of dilutive incentive awards
 
0.9

 
0.8

 
1.2

Weighted average number of units—diluted
 
305.4

 
251.7

 
214.1


6. Inventories
The components of inventories are as follows:
 
 
December 31,
 
 
2016
 
2015
 
 
(in millions)
Crude oil
 
$
683

 
$
424

NGLs
 
126

 
83

Refined products
 
110

 
83

Refined products additives
 
3

 
3

Materials, supplies and other
 
12

 
14

     Total Inventories
 
$
934

 
$
607

The Partnership's lower of cost or market ("LCM") reserves totaled $233 and $17 million at December 31, 2016 on its crude oil and NGLs inventories, respectively. At December 31, 2015, the LCM reserves totaled $381, $37, and $2 million on the Partnership's crude oil, NGLs and refined products inventories, respectively. See Note 18 for additional information on the LCM adjustments related to the Partnership's LIFO inventory balances, which are reported as impairment charge and other matters within the consolidated statement of comprehensive income.

7. Properties, Plants and Equipment
The components of net properties, plants and equipment are as follows:
 
 
 
 
December 31,
 
 
Estimated
Useful Lives
 
2016
 
2015
 
 
(in years)
 
(in millions)
Land and land improvements (including rights-of-way) (1)
 
—
 
$
1,357

 
$
1,286

Pipelines and related assets
 
16 - 39
 
6,348

 
5,634

Terminals and storage facilities
 
20 - 41
 
2,905

 
2,294

Buildings and improvements
 
25 - 32
 
544

 
509

Other
 
 3 - 20
 
185

 
177

Construction-in-progress
 
 
 
2,212

 
1,627

Total properties, plants and equipment (2)
 
 
 
13,551

 
11,527

Less: Accumulated depreciation and amortization
 
 
 
(1,227
)
 
(835
)
Total properties, plants and equipment, net
 
 
 
$
12,324

 
$
10,692

(1) 
As of December 31, 2016 and 2015, the Partnership had rights-of-way with a book value of $1.1 billion.
(2) 
As of December 31, 2016 and 2015, accrued capital expenditures were $249 and $286 million, respectively.



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8. Investment in Affiliates
The Partnership's ownership percentages in equity ownership interests as of December 31, 2016 and 2015 were as follows:
 
 
December 31,
 
2016
 
2015
Explorer Pipeline Company
15.0%
 
13.3%
Yellowstone Pipe Line Company
14.0%
 
14.0%
West Shore Pipe Line Company
17.1%
 
17.1%
Wolverine Pipe Line Company
31.5%
 
31.5%
Bayview Refining Company, LLC
49.0%
 
49.0%
Permian Express Terminal LLC (formerly known as SunVit Pipeline LLC) (1)
100.0%
 
50.0%
Bayou Bridge Pipeline LLC
30.0%
 
30.0%
Bakken Holdings Company LLC ("Bakken HoldCo") (2)

40.0%
 
40.0%
(1) 
Effective November 1, 2016, SunVit Pipeline LLC became a wholly-owned, consolidated subsidiary of the Partnership, and was subsequently renamed Permian Express Terminal LLC in December 2016.
(2) 
The investment in Bakken HoldCo provides the Partnership with a 30 percent overall ownership interest in the Bakken pipeline project through its ownership in the subsidiary companies which will operate the pipeline system.
Explorer Pipeline Company
In the third quarter 2016, the Partnership purchased an additional 1.7 percent ownership interest in Explorer from EXPL Pipeline Investment LLC for $17 million, increasing the Partnership's ownership interest to 15.0 percent. Explorer owns a refined products pipeline running from the Gulf Coast of the United States to the Chicago, Illinois area. The investment continues to be accounted for as an equity method investment within the Partnership's Refined Products segment.
Permian Express Terminal
In November 2016, the Partnership acquired an additional 50 percent interest in SunVit from Vitol, which increased the Partnership's overall ownership of SunVit to 100 percent. In December 2016, the Partnership renamed the SunVit pipeline to Permian Express Terminal LLC ("PET"). See Note 3 for additional information on the acquisition from Vitol.
Bayou Bridge Pipeline
In July 2015, the Partnership entered into an agreement with ETP and Phillips 66 to participate in the Bayou Bridge Pipeline project. The Partnership obtained a 30 percent economic interest in the project which is a consolidated subsidiary of ETP. The project consists of a newly constructed pipeline that will deliver 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 commence operations in the fourth quarter 2017. The Partnership is the operator of the pipeline and continues to fund its proportionate share of the cost of the project, which is accounted for as an equity method investment within the Partnership's Crude Oil segment.
Bakken Pipeline
In October 2015, the Partnership finalized its participation in the Bakken pipeline project with ETP and Phillips 66. The Partnership obtained a 30 percent economic interest in the project which is a consolidated subsidiary of ETP. The 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 the Partnership's Nederland terminal. The ultimate takeaway capacity target for the project is 570 thousand barrels per day. The Partnership expects to reach agreement to become the operator of the pipeline system, which is expected to begin commercial operations in the second quarter 2017.
In exchange for its 30 percent economic interest in the project, the Partnership issued 9.4 million Class B units to ETP, representing limited partner interests in the Partnership, and paid $382 million in cash representing the Partnership's proportionate share of contributions at the time of closing. Since the interest in the project was acquired from a related party, the Partnership's investment was recorded at ETP's historical carrying value. The Partnership's investment in the Bakken Pipeline project is reflected as an equity method investment within the Crude Oil segment. See Note 4 for additional information on the issuance of the Class B units.

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In August 2016, ETP, Sunoco Logistics and Phillips 66 established a $2.5 billion credit facility to provide substantially all of the remaining capital necessary to complete the project. Borrowings under the credit facility are secured by all assets of the Bakken entities, as well as the ownership interests maintained by the joint partners. The facility was limited to $1.1 billion in borrowings until attainment of certain closing conditions, which were met in February 2017. At December 31, 2016, $1.1 billion was outstanding under the Bakken credit facility.
The joint partners agreed to provide the Bakken entities with a short-term loan until the full capacity of the $2.5 billion credit facility was available. The loan was made by the partners in proportion to their respective ownership interests. The outstanding balance of the note receivable due to the Partnership by the Bakken entities at December 31, 2016 was $301 million and was repaid in February 2017.
In February 2017, the Partnership and ETP completed the sale of 49 percent of their respective interests in the Bakken Pipeline project for $2.0 billion to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P. The Partnership received $800 million for its interest. The carrying amount of the Partnership's investment in the Bakken Pipeline project was $639 million at December 31, 2016. As a result of the sale, the Partnership's ownership interest in the Bakken Pipeline project is 15.3 percent.
At December 31, 2016, the Partnership's investments in Explorer Pipeline Company, Yellowstone Pipe Line Company, West Shore Pipe Line Company and Wolverine Pipe Line Company included net excess investment amounts of $135 million. The excess investment is the difference between the investment balances and the Partnership's equity in the net assets of the entities. The Partnership has not provided additional financial support to any of these joint ventures during the 2014 through 2016 periods.
The Partnership had $63 million of undistributed earnings from its investments in joint ventures within equity at December 31, 2016. During the years ended December 31, 2016, 2015 and 2014, the Partnership recorded equity income of $39, $24, and $25 million, respectively, and received dividends of $25, $23, and $14 million, respectively, from its investments in joint ventures.

9. Goodwill and Other Intangible Assets
Goodwill
Goodwill, which represents the excess of the purchase price in a business combination over the fair value of net assets acquired, is tested for impairment annually in the fourth quarter, or more often if events or changes in circumstances indicate that the carrying value of goodwill may exceed its estimated fair value. The Partnership's goodwill balance at December 31, 2016 and 2015 was $1,609 and $1,358 million, respectively. The $251 million increase in the Partnership's goodwill balance resulted from the Partnership's November 2016 acquisition from Vitol (Note 3). There were no goodwill impairments recorded during the 2014 through 2016 period.
In connection with the change in the Partnership's reporting segments in the fourth quarter 2015, goodwill was reassigned to the new reporting segments. The Partnership's legacy Crude Oil Pipelines, Crude Oil Acquisition and Marketing, and Terminal Facilities segments included goodwill of $200, $557, and $601 million, respectively. The goodwill related to the legacy Crude Oil Pipelines and Crude Oil Acquisition and Marketing segments was combined under the Partnership's new segment alignment, while the goodwill related to the legacy Terminal Facilities segment was allocated to the new segments based on a relative fair value basis. Subsequent to the realignment of its reporting segments, the Partnership's Crude Oil, Natural Gas Liquids, and Refined Products segments include goodwill of $912, $357, and $89 million, respectively, at December 31, 2015.
The Partnership will continue to monitor the volatility in the energy markets and the impact it could have on the estimated fair value of its reporting segments. It is possible that continued negative volatility within these markets could change the Partnership's conclusion regarding whether goodwill is impaired.
Identifiable Intangible Assets
The Partnership's identifiable intangible assets are comprised of customer relationships and patented technology associated with the Partnership's butane blending services. The values assigned to these intangible assets are amortized to earnings using a straight-line approach, over a weighted average amortization period of approximately 17 years. Amortization expense related to these intangibles was $54, $52, and $52 million for the years ended December 31, 2016, 2015 and 2014, respectively. The $313 million increase in the Partnership's intangible assets is attributable to customer relationships acquired in connection with its acquisition from Vitol (Note 3).


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Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations or asset purchases whereby (i) the Partnership acquired information about or access to customers, (ii) the customers now have the ability to transact business with the Partnership and (iii) the Partnership is positioned, due to limited competition, to provide products or services to the customers. The customer relationship intangible assets are amortized on a straight-line basis over their respective economic lives. Technology-related intangible assets consist of the Partnership's patents for blending of butane into refined products. These patents are amortized over their remaining legal lives.
 
 
Weighted Average
Amortization Period
 
December 31,
 
 
 
2016
 
2015
 
 
(in years)
 
(in millions)
Gross
 
 
 
 
 
 
Customer relationships
 
18
 
$
1,149

 
$
836

Technology
 
10
 
47

 
47

Total gross
 
 
 
1,196

 
883

Accumulated amortization
 
 
 
 
 
 
Customer relationships
 
 
 
(199
)
 
(149
)
Technology
 
 
 
(20
)
 
(16
)
Total accumulated amortization
 
 
 
(219
)
 
(165
)
Total Net
 
 
 
$
977

 
$
718

The Partnership forecasts $69 million of annual amortization expense for each year through the year 2021 for its intangible assets.
Intangible assets attributable to rights-of-way are included in properties, plants and equipment in the Partnership's consolidated balance sheets at December 31, 2016 and 2015 (Note 7).















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10. Debt
The components of the Partnership's long-term debt balances are as follows:
 
 
December 31,
 
 
2016
 
2015
 
 
(in millions)
Credit Facilities
 
 
 
 
$2.50 billion Credit Facility, due March 2020 (1)
 
$
1,292

 
$
562

$1.0 billion 364-Day Credit Facility, due December 2017 (2)
 
630

 
—

 
 
 
 
 
Senior Notes
 
 
 
 
Senior Notes - 6.125%, due May 2016 (3)
 
—

 
175

Senior Notes - 5.50%, due February 2020
 
250

 
250

Senior Notes - 4.40%, due April 2021
 
600

 
600

Senior Notes - 4.65%, due February 2022
 
300

 
300

Senior Notes - 3.45%, due January 2023
 
350

 
350

Senior Notes - 4.25%, due April 2024
 
500

 
500

Senior Notes - 5.95%, due December 2025
 
400

 
400

Senior Notes - 3.90%, due July 2026
 
550

 
—

Senior Notes - 6.85%, due February 2040
 
250

 
250

Senior Notes - 6.10%, due February 2042
 
300

 
300

Senior Notes - 4.95%, due January 2043
 
350

 
350

Senior Notes - 5.30%, due April 2044
 
700

 
700

Senior Notes - 5.35%, due May 2045
 
800

 
800

Unamortized fair value adjustments (4)
 
84

 
93

Total debt
 
7,356

 
5,630

Less:
 
 
 
 
Unamortized bond discount and debt issuance costs (5)
 
(43
)
 
(39
)
Long-term debt
 
$
7,313

 
$
5,591

(1) 
Includes $50 million of commercial paper outstanding at December 31, 2016. There was no commercial paper outstanding at December 31, 2015.
(2) 
The $1.0 billion 364-Day Credit Facility, including its $630 million term loan, is classified as long-term debt at December 31, 2016 as the Partnership has the ability and intent to refinance such borrowings on a long-term basis.
(3) 
The 6.125 percent Senior Notes were classified as long-term debt at December 31, 2015 as the Partnership repaid these notes in May 2016 with borrowings under its $2.50 billion Credit Facility, due in 2020.
(4) 
Represents fair value adjustments on senior notes resulting from the application of push-down accounting in connection with the acquisition of the Partnership's general partner by ETP on October 5, 2012.
(5) 
In the fourth quarter 2015, the Partnership adopted accounting guidance which requires certain debt issuance costs to be reflected as a reduction in the total long-term debt liability for all periods presented. The net long-term debt balance now includes $34 and $32 million of debt issuance costs at December 31, 2016 and 2015, respectively.







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The aggregate amount of long-term debt instrument maturities are as follows:
Year Ended December 31,
(in millions)
2017
$
630

2018
—

2019
—

2020
1,542

2021
600

Thereafter
4,500

Total
$
7,272

Cash payments for interest related to long-term debt instruments, net of capitalized interest (Note 2), were $152, $137, and $64 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Credit Facilities
In March 2015, the Operating Partnership amended and restated its $1.50 billion Credit Facility, which was scheduled to mature in November 2018. The amended and restated credit facility is a $2.50 billion unsecured revolving credit agreement (the "$2.50 billion Credit Facility"), which matures in March 2020, will continue to fund the Partnership's working capital requirements, finance acquisitions and capital projects, and be used for general partnership purposes. The $2.50 billion Credit Facility contains an "accordion" feature, under which the total aggregate commitment may be extended to $3.25 billion under certain conditions. In June 2015, the $2.50 billion Credit Facility was amended to create a segregated tranche of borrowings that will be guaranteed by ETP. The amendment did not modify the outstanding borrowings, total capacity or terms of the facility. In September 2015, the Operating Partnership initiated a commercial paper program under the borrowing limits established by its $2.50 billion Credit Facility. The facility bears interest at LIBOR or the Base Rate, as defined in the facility, each plus an applicable margin. The credit facility may be repaid at any time.
The $2.50 billion Credit Facility contains various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of the business of the Partnership and its subsidiaries. The credit facility also limits the Partnership, on a rolling four quarter basis, to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. The Partnership's ratio of total consolidated debt to consolidated Adjusted EBITDA was 4.4 to 1 at December 31, 2016, as calculated in accordance with the credit agreement.
In December 2016, the Operating Partnership entered into an agreement for a 364-day maturity credit facility ("364-Day Credit Facility") with a total lending capacity of $1.0 billion, including a $630 million term loan. The terms of the 364-Day Credit Facility are similar to those of the $2.50 billion Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. The 364-Day Credit Facility is used to fund the Partnership's working capital requirements and for general partnership purposes. The facility bears interest at LIBOR or the Base Rate, as defined in the facility, each plus an applicable margin. The credit facility may be repaid at any time, and is expected to be terminated and repaid in connection with completion of the Merger.
See Note 8 for additional information on the Bakken Pipeline project-level financing.
Senior Notes
The Operating Partnership had $175 million of 6.125 percent Senior Notes which matured and were repaid in May 2016, using borrowings under the $2.50 billion Credit Facility.
In July 2016, the Operating Partnership issued $550 million of 3.90 percent Senior Notes (the "2026 Senior Notes"), due July 2026.
In November 2015, the Partnership issued $600 million of 4.40 percent senior notes and $400 million of 5.95 percent senior notes (the "2021 and 2025 Senior Notes"), due April 2021 and December 2025, respectively.
The net proceeds of $544 and $991 million from the 2016 and 2015 senior notes offerings, respectively, were used to repay outstanding borrowings on the $2.50 billion Credit Facility and for general partnership purposes. The terms and conditions of these senior notes offerings are comparable to those under other outstanding senior notes.
Debt Guarantee
The Partnership currently serves as guarantor of the senior notes and of any obligations under its credit facilities. This guarantee is full and unconditional. See Note 20 for supplemental condensed consolidating financial information.

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11. Commitments and Contingent Liabilities
Total rental expense for the years ended December 31, 2016, 2015 and 2014 amounted to $22, $22, and $18 million, respectively. The Partnership, as lessee, has non-cancelable operating leases for office space and equipment for which the aggregate amount of future minimum annual rentals as of December 31, 2016 is as follows:
Year Ended December 31,
(in millions)
2017
$
7

2018
4

2019
3

2020
3

2021
—

Thereafter
—

Total
$
17

The Partnership is subject to numerous federal, state and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. These laws and regulations result in liabilities and loss contingencies for remediation at the Partnership's facilities and at third-party or formerly owned sites. At December 31, 2016 and 2015, there were accrued liabilities for environmental remediation in the consolidated balance sheets of $4 and $6 million, respectively. The accrued liabilities for environmental remediation do not include any amounts attributable to unasserted claims, since there are no unasserted claims that are probable of settlement or reasonably estimable, nor have any recoveries from insurance been assumed. Charges against income for environmental remediation totaled $10, $8, and $15, million for the years ended December 31, 2016, 2015 and 2014, respectively. The Partnership maintains insurance programs that cover certain of its existing or potential environmental liabilities. Claims for recovery of environmental liabilities and previous expenditures that are probable of realization were not material in relation to the Partnership's consolidated financial position at December 31, 2016 and 2015.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites; the determination of the extent of the contamination at each site; the timing and nature of required remedial actions; the technology available and needed to meet the various existing legal requirements; the nature and extent of future environmental laws, inflation rates and the determination of the Partnership's liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability; and the number, participation levels and financial viability of other parties. Management believes it is reasonably possible that additional environmental remediation losses will be incurred. At December 31, 2016, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled $13 million.
The Partnership is a party to certain pending and threatened claims. Although the ultimate outcome of these claims cannot be ascertained at this time, nor can a range of reasonably possible losses be determined, it is reasonably possible that some portion of them could be resolved unfavorably to the Partnership. Management does not believe that any liabilities which may arise from such claims and the environmental matters discussed above would be material in relation to the Partnership's results of operations, financial position or cash flows at December 31, 2016. Furthermore, management does not believe that the overall costs for such matters will have a material impact, over an extended period of time, on the Partnership's financial position, results of operations or cash flows.
Sunoco has indemnified the Partnership for 30 years from environmental and toxic tort liabilities related to the assets contributed to the Partnership, that arose from the operation of such assets prior to the closing of the February 2002 initial public offering ("IPO"). Sunoco has also indemnified the Partnership for 100 percent of all losses asserted within the first 21 years after the closing of the IPO. Sunoco's share of liability for claims asserted thereafter will decrease by 10 percent per year. For example, for a claim asserted during the twenty-third year after closing of the IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on the amount of indemnity coverage provided by Sunoco. The Partnership has agreed to indemnify Sunoco for events and conditions associated with the operation of the Partnership's assets that occur on or after the closing of the IPO and for environmental and toxic tort liabilities to the extent Sunoco is not required to indemnify the Partnership.
Management of the Partnership does not believe that any liabilities which may arise from claims indemnified by Sunoco would be material in relation to the Partnership's financial position, results of operations or cash flows at December 31, 2016. There are certain other pending legal proceedings related to matters arising after the IPO that are not indemnified by Sunoco. Management believes that any liabilities that may arise from these legal proceedings will not be material in relation to the Partnership's financial position, results of operations or cash flows at December 31, 2016.


93


12. Equity
The Partnership maintains an at-the-market equity offering program which allows the Partnership to issue common units directly to the public and raise capital in a timely and efficient manner to finance its growth capital program, while supporting the Partnership's investment-grade credit ratings. For the years ended December 31, 2016 and 2015, the Partnership issued 29.1 and 26.8 million common units under this program, for proceeds of $744 and $890 million, net of $8 and $10 million in fees and commissions to managers, respectively.
In September and October 2016, a total of 24.2 million common units were issued for total proceeds of $652 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Total proceeds of $648 million were used to repay outstanding borrowings under the Partnership's $2.50 billion Credit Facility and for general partnership purposes.
Formation of Permian Express Partners
In February 2017, the Partnership formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil. The Partnership contributed its 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. The Partnership's ownership percentage, upon formation, is approximately 85 percent. Upon commencement of operations on the Bakken pipeline, the Partnership will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of the Partnership with its operating results included in the Crude Oil segment. ExxonMobil's interest will be reflected as a noncontrolling interest in the Partnership's consolidated balance sheets.

13. Cash Distributions
Within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership's business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as "incentive distributions." The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
The following table shows the target distribution levels and distribution "splits" between the general partner and the holders of the Partnership's common units at December 31, 2016:
 
 
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.




94



Distributions paid by the Partnership on its common units for the periods presented were as follows:
Cash Distribution Payment Date
 
Cash Distribution per Limited Partner Unit
 
Annualized Cash Distribution per Limited
Partner Unit
 
Total Cash Distribution to the Limited Partners
 
Total Cash Distribution to the General Partner
 
 
 
 
 
 
(in millions)
 
(in millions)
November 14, 2016
 
$
0.5100

 
$
2.0400

 
$
164

 
$
102

August 12, 2016
 
$
0.5000

 
$
2.0000

 
$
149

 
$
98

May 13, 2016
 
$
0.4890

 
$
1.9560

 
$
140

 
$
92

February 12, 2016
 
$
0.4790

 
$
1.9160

 
$
131

 
$
85

November 13, 2015
 
$
0.4580

 
$
1.8320

 
$
119

 
$
76

August 14, 2015
 
$
0.4380

 
$
1.7520

 
$
111

 
$
69

May 15, 2015
 
$
0.4190

 
$
1.6760

 
$
103

 
$
62

February 13, 2015
 
$
0.4000

 
$
1.6000

 
$
92

 
$
54

November 14, 2014
 
$
0.3825

 
$
1.5300

 
$
84

 
$
49

August 14, 2014
 
$
0.3650

 
$
1.4600

 
$
77

 
$
43

May 15, 2014
 
$
0.3475

 
$
1.3900

 
$
72

 
$
39

February 14, 2014
 
$
0.3312

 
$
1.3248

 
$
69

 
$
35

In connection with the acquisition from Vitol, the Partnership's general partner executed an amendment to the Partnership's Third Amended and Restated Agreement of Limited Partnership in September 2016, which provides for a reduction to the incentive distributions the general partner receives from the Partnership. 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.
On January 26, 2017, the Partnership declared a cash distribution of $0.52 per unit ($2.08 per unit, annualized) on its outstanding common units, representing the distribution for the quarter ended December 31, 2016. The $272 million distribution, including $105 million to the general partner, was paid on February 14, 2017 to unitholders of record at the close of business on February 7, 2017.

14. Management Incentive Plan
In December 2015, the Partnership's unitholders approved the Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated (the "Restated LTIP"), which was previously approved by the board of directors of Sunoco Partners LLC, the Partnership's general partner. The Restated LTIP authorized an additional 10.0 million common units to be available under the plan; added additional types of awards that can be granted under the plan, such as phantom unit awards, unit appreciation rights, unrestricted unit awards and other unit-based awards ("plan awards"); added a prohibition on repricing of unit options and unit appreciation rights without the approval of the unitholders; provided for termination of the plan at the earliest date it is terminated by the board of directors, the date no more units remain available for grants, and December 1, 2025; and incorporated certain other administrative changes.
The Restated LTIP benefits eligible employees and directors of the general partner and its affiliates who perform services for the Partnership. The Restated LTIP is administered by the independent directors of the Compensation Committee of the general partner's board of directors with respect to employee awards, and by the general partner's board of directors with respect to awards granted to the independent directors. At December 31, 2016, there were 8.6 million plan awards available for future grants under the Restated LTIP.
Restricted Units
A restricted unit entitles the grantee to receive a common unit or, at the discretion of the Compensation Committee, an amount of cash equivalent to the value of a common unit upon the vesting of the unit. Such grants may include requirements related to the attainment of predetermined performance targets. The Compensation Committee may make additional grants under the Restated LTIP to employees and directors containing such terms as defined by the Compensation Committee. Common units to be delivered to the grantee upon vesting may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person, or any combination of the foregoing. The general partner will be entitled to reimbursement by

95


the Partnership for the cost incurred in acquiring common units. If the Partnership issues new common units upon vesting of the restricted units, the total number of common units outstanding will increase.
The Compensation Committee, at its discretion, may grant tandem distribution equivalent rights ("DERs") related to the restricted units. Subject to applicable vesting criteria, DERs entitle the grantee to receive an amount of cash equal to the per unit cash distributions made by the Partnership during the period the restricted unit is outstanding. All units granted during the periods presented below included tandem DERs.
The Partnership's outstanding restricted unit awards are time-vested grants, the vesting of which occurs over a five-year period, and is conditioned solely upon continued employment or service as of the applicable vesting date.
The following table summarizes information regarding restricted unit award activity for the periods presented:
 
 
Number of Units
 
Weighted Average
Grant Date Fair Value
Granted, non-vested and outstanding, December 31, 2013
 
1,279,162

 
$
26.19

Granted
 
719,009

 
$
41.59

Performance factor adjustment (1)
 
229,828

 
$
17.52

Vested
 
(693,326
)
 
$
20.26

Cancelled/forfeited
 
(72,872
)
 
$
30.10

Granted, non-vested and outstanding, December 31, 2014
 
1,461,801

 
$
35.01

 Granted
 
1,412,257

 
$
29.54

 Vested
 
(245,563
)
 
$
22.08

 Cancelled/forfeited
 
(90,776
)
 
$
36.83

Granted, non-vested and outstanding, December 31, 2015
 
2,537,719

 
$
33.16

 Granted
 
1,300,255

 
$
23.21

 Vested
 
(526,014
)
 
$
34.19

 Cancelled/forfeited
 
(98,440
)
 
$
33.72

Granted, non-vested and outstanding, December 31, 2016
 
3,213,520

 
$
28.57

(1) 
Certain awards granted prior to October 5, 2012 were subject to the Partnership achieving certain market-based and cash distribution performance targets as compared to a peer group average, or certain cash distribution performance targets as defined by the Compensation Committee, which caused the actual amount of units that ultimately vested to range between 0 to 200 percent of the original units granted.
The total fair value of restricted unit awards vested for the years ended December 31, 2016, 2015 and 2014, was $12, $8, and $30 million, respectively, based on the market price of the Partnership's common units as of the vesting date. As of December 31, 2016, estimated compensation cost related to non-vested awards not yet recognized was $57 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years. The fair value of the Partnership's time-vested awards is based on the grant date market price of the Partnership's common units.
The Partnership recognizes compensation expense on a straight-line basis over the requisite service period, and estimates forfeitures over the requisite service period when recognizing compensation expense.
Based on the unit grants and performance factor adjustments outlined in the table above, the Partnership recognized unit-based compensation expense related to the awards granted within operating expenses and selling, general and administrative expenses in the consolidated statements of comprehensive income of $23, $17, and $16 million for the years ended December 31, 2016, 2015 and 2014, respectively. The tandem DERs associated with the restricted unit grants are recognized as a reduction of equity when earned.






96


15. Derivatives and Risk Management
The Partnership is exposed to various risks, including volatility in the prices of the products that the Partnership markets, counterparty credit risk and changes in interest rates.
Price Risk Management
The Partnership is exposed to risks associated with changes in the market price of crude oil, NGLs and refined products. These risks are primarily associated with price volatility related to pre-existing or anticipated purchases, sales and storage. Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations. In order to manage such exposure, the Partnership's policy is (i) to only purchase crude oil, NGLs and refined products for which sales contracts have been executed or for which ready markets exist, (ii) to structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) to not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. Although the Partnership seeks to maintain a balanced inventory position within its commodity inventories, net unbalances may occur for short periods of time due to production, transportation and delivery variances. When physical inventory builds or draws do occur, the Partnership continuously manages the variance to a balanced position over a period of time.
The physical contracts related to the Partnership's commodity purchase and sale activities that qualify as derivatives have been designated as normal purchases and sales and are accounted for using accrual accounting under United States' generally accepted accounting principles. The Partnership accounts for derivatives that do not qualify as normal purchases or sales at fair value. The Partnership currently does not utilize derivative instruments to manage its exposure to prices related to crude oil sale activities. All derivative balances are presented on a gross basis.
Pursuant to the Partnership's approved risk management policy, derivative contracts, such as swaps, futures and other derivative instruments, may be used to hedge or reduce exposure to price risk associated with acquired inventory or forecasted physical transactions. The Partnership utilizes derivative instruments to mitigate the risk associated with market movements in the price of crude oil, NGLs, refined products, and other commodities as necessary. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing the Partnership to transfer this price risk to counterparties who are able and willing to bear it. The Partnership has no derivative contracts designated as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statement of comprehensive income in the period in which they occur. All realized gains and losses associated with the Partnership's derivative contracts are recorded in earnings in the same line item associated with the forecasted transaction (either sales and other operating revenue, cost of products sold or operating expenses).
The Partnership had open derivative positions on 9.2 million barrels of crude oil, NGLs and refined products at December 31, 2016 and 2015. The derivatives outstanding at December 31, 2016 vary in duration but do not extend beyond one year. The Partnership records its derivatives at fair value based on observable market prices (levels 1 and 2), of which positions at December 31, 2016 and 2015 were primarily categorized at level 2. As of December 31, 2016 and 2015, the fair values of the Partnership's derivative assets and liabilities were: 
 
 
December 31,
 
 
2016
 
2015
 
 
(in millions)
Derivative assets
 
$
19

 
$
30

Derivative liabilities
 
(46
)
 
(18
)
 
 
$
(27
)
 
$
12

Derivative asset and liability balances are recorded in accounts receivable and accrued liabilities, respectively, in the consolidated balance sheets.

97


The following table sets forth the impact of derivatives on the Partnership's results of operations for the periods presented:
 
Location of Gains (Losses)
Recognized in Earnings
 
Gains (Losses) Recognized in Earnings
 
 
 
(in millions)
Year Ended December 31, 2016
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
Sales and other operating revenue
 
$
(65
)
Commodity contracts
Cost of products sold
 
6

 
 
 
$
(59
)
Year Ended December 31, 2015
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
Sales and other operating revenue
 
$
47

Commodity contracts
Cost of products sold
 
(26
)
Commodity contracts
Operating expenses
 
(1
)
 
 
 
$
20

Year Ended December 31, 2014
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
Commodity contracts
Sales and other operating revenue
 
$
81

Commodity contracts
Cost of products sold
 
(20
)
 
 
 
$
61

Credit Risk Management
The Partnership maintains credit policies with regard to its counterparties that management believes minimize the overall credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The credit positions of the Partnership's customers are analyzed prior to the extension of credit and periodically after credit has been extended. The Partnership's counterparties consist primarily of financial institutions and major integrated oil companies. This concentration of counterparties may impact the Partnership's overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
Interest Rate Risk Management
The Partnership has interest rate risk exposure for changes in interest rates related to its outstanding borrowings. The Partnership manages its exposure to changes in interest rates through the use of a combination of fixed-rate and variable-rate financial instruments. At December 31, 2016, the Partnership had $1.9 billion of consolidated variable-rate borrowings under its credit facilities, including $50 million of commercial paper products and the $630 million term loan.

16. Fair Value Measurements
The estimated fair value of the Partnership's financial instruments has been determined based on management's assessment of available market information and appropriate valuation methodologies. The Partnership's current assets (other than derivatives and inventories) and current liabilities (other than derivatives) are financial instruments and most of these items are recorded at cost in the consolidated balance sheets. The estimated fair value of these financial instruments approximates their carrying value due to their short-term nature. The Partnership's derivatives are measured and recorded at fair value based on observable market prices. The estimated fair value of the Partnership's senior notes is determined using observable market prices, as these notes are actively traded (level 1). The estimated aggregate fair value of the senior notes at December 31, 2016 was $5.4 billion, compared to the carrying amount of $5.4 billion. The estimated aggregate fair value of the senior notes at December 31, 2015 was $4.2 billion, compared to the carrying amount of $5.1 billion.
For further information regarding the Partnership's fair value measurements, see Notes 2, 3, 12 and 15.





98


17. Concentration of Credit Risk
The Partnership's trade relationships are primarily with major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect the Partnership's overall credit risk as the customers may be similarly affected by changes in economic, regulatory or other factors. The Partnership maintains credit policies with regard to its counterparties that management believes minimize the overall credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. The credit positions of the Partnership's customers are analyzed prior to the extension of credit and periodically after it has been extended. For certain transactions, the Partnership may utilize letters of credit, prepayments, guarantees and secured interests in assets.
In 2016, approximately 12 percent of the Partnership's total revenues, respectively, were derived from one investment-grade customer with crude oil sales and other revenues comprising greater than 10 percent of total revenues. In 2015, approximately 23 percent of the Partnership's total revenues were derived from two investment-grade customers with crude oil sales and other revenues. While this concentration has the ability to negatively impact revenues going forward, management does not anticipate a material adverse effect in the Partnership's financial position, results of operations or cash flows as the absolute price levels for crude oil normally do not bear a relationship to gross profit. In addition, these customers are subject to netting arrangements which allow the Partnership to offset payable activities and mitigate credit exposure.

18. Business Segment Information
The Partnership operates in 37 states throughout the United States and in three principal business segments.
During the fourth quarter 2015, the Partnership realigned its reporting segments as a result of the continued investment in its organic growth capital program which has served to increase the integration that exists between its 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 the Partnership's financial results. The updated reporting segments are: Crude Oil, Natural Gas Liquids and Refined Products. The new segmentation provides the Partnership's investors with a more meaningful view of its 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 presentation. Such recasts had no impact on previously reported consolidated earnings.
•
The Crude Oil segment provides transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern 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 2 million barrels at our Midland, Texas terminal and approximately 3 million barrels at our Fort Mifflin terminal complex in Pennsylvania. 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, utilizing 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.

99


The following table sets forth consolidated statement of comprehensive income information concerning the Partnership's business segments and reconciles total segment Adjusted EBITDA to net income attributable to SXL for the periods presented:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Sales and other operating revenue (1)
 
 
 
 
 
 
Crude Oil
 
$
7,496

 
$
8,956

 
$
16,899

Natural Gas Liquids
 
875

 
1,165

 
959

Refined Products
 
780

 
365

 
230

Total sales and other operating revenue
 
$
9,151

 
$
10,486

 
$
18,088

Depreciation and amortization
 
 
 
 
 
 
Crude Oil
 
$
242

 
$
216

 
$
191

Natural Gas Liquids
 
105

 
76

 
30

Refined Products
 
99

 
90

 
75

Total depreciation and amortization
 
$
446

 
$
382

 
$
296

Impairment charge and other matters (2)
 
 
 
 
 
 
Crude Oil
 
$
(148
)
 
$
150

 
$
231

Natural Gas Liquids
 
(20
)
 
10

 
27

Refined Products
 
(2
)
 
2

 
—

Total impairment charge and other matters
 
$
(170
)
 
$
162

 
$
258

Capital expenditures (3)
 
 
 
 
 
 
Crude Oil
 
$
547

 
$
1,377

 
$
801

Natural Gas Liquids
 
1,258

 
1,111

 
1,210

Refined Products
 
91

 
197

 
534

Corporate
 
16

 
24

 
14

Total capital expenditures
 
$
1,912

 
$
2,709

 
$
2,559

Adjusted EBITDA
 
 
 
 
 
 
Crude Oil
 
$
687

 
$
656

 
$
669

Natural Gas Liquids
 
317

 
333

 
203

Refined Products
 
229

 
164

 
99

Total Adjusted EBITDA
 
1,233

 
1,153

 
971

Interest expense, net
 
(157
)
 
(134
)
 
(67
)
Depreciation and amortization expense
 
(446
)
 
(382
)
 
(296
)
Impairment charge and other matters
 
170

 
(162
)
 
(258
)
Provision for income taxes
 
(27
)
 
(21
)
 
(25
)
Non-cash compensation expense
 
(23
)
 
(17
)
 
(16
)
Unrealized gains (losses) on commodity risk management activities
 
(39
)
 
(4
)
 
17

Amortization of excess equity method investment
 
(2
)
 
(2
)
 
(2
)
Proportionate share of unconsolidated affiliates' interest, depreciation and provision for income taxes
 
(41
)
 
(34
)
 
(24
)
Gain on investment in affiliate
 
41

 
—

 
—

Net Income (4)
 
709

 
397

 
300

Net income attributable to noncontrolling interests
 
3

 
3

 
9

Net income attributable to redeemable noncontrolling interests
 
1

 
1

 
—

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

 
$
393

 
$
291








100


(1) 
Sales and other operating revenue for the periods presented includes the following amounts from ETP and its affiliates:
 
 
Year Ended December 31,
 
 
2016
 
2015
 
2014
 
 
(in millions)
Crude Oil
 
$
24

 
$
193

 
$
866

Natural Gas Liquids
 
175

 
204

 
134

Refined Products
 
237

 
118

 
70

Total sales and other operating revenue
 
$
436

 
$
515

 
$
1,070

Total sales and other operating revenue exclude $483, $404, and $309 million attributable to intrasegment activity for the years ended December 31, 2016, 2015 and 2014, respectively.
(2) 
Represents non-cash adjustments on the Partnership's crude oil, NGLs and refined products inventories.
(3) 
Total capital expenditures exclude acquisitions and investments in equity ownership interests of $796, $131, and $448 million for the years ended December 31, 2016, 2015 and 2014, respectively.
(4) 
Net income includes $39, $24, and $25 million for the years ended December 31, 2016, 2015 and 2014, respectively, of equity income attributable to the equity ownership interest.
The following table provides consolidated balance sheet information concerning the Partnership's business segments as of December 31, 2016, 2015 and 2014, respectively:
 
 
Crude Oil
 
Natural Gas Liquids
 
Refined Products
 
Total
 
 
(in millions)
As of December 31, 2016
 
 
 
 
 
 
 
 
   Investment in affiliates
 
$
745

 
$
—

 
$
207

 
$
952

   Goodwill
 
$
1,163

 
$
357

 
$
89

 
$
1,609

   Identifiable assets (1)
 
$
10,939

 
$
4,937

 
$
2,795

 
$
18,849

As of December 31, 2015
 
 
 
 
 
 
 
 
   Investment in affiliates
 
$
623

 
$
—

 
$
179

 
$
802

   Goodwill
 
$
912

 
$
357

 
$
89

 
$
1,358

   Identifiable assets (2)
 
$
8,802

 
$
3,764

 
$
2,747

 
$
15,489

As of December 31, 2014
 
 
 
 
 
 
 
 
   Investment in affiliates
 
$
53

 
$
—

 
$
173

 
$
226

   Goodwill
 
$
912

 
$
357

 
$
89

 
$
1,358

   Identifiable assets (3)
 
$
8,579

 
$
2,401

 
$
2,458

 
$
13,618

(1) 
Total identifiable assets include the Partnership's unallocated $15 million cash and cash equivalents, $153 million of properties, plants and equipment, net, and $10 million of other assets.
(2) 
Total identifiable assets include the Partnership's unallocated $36 million cash and cash equivalents, $133 million of properties, plants and equipment, net, and $7 million of other assets.
(3) 
Total identifiable assets include the Partnership's unallocated $47 million cash and cash equivalents, $124 million of properties, plants and equipment, net, and $9 million of other assets.








101


19. Quarterly Financial Data (Unaudited)
Summarized quarterly financial data is as follows:
 
 
1st Quarter
 
2nd Quarter
 
3rd Quarter
 
4th Quarter
 
 
(in millions, except per unit amounts)
2016
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
1,668

 
$
2,174

 
$
2,085

 
$
2,788

Affiliates
 
$
109

 
$
94

 
$
104

 
$
129

Gross profit (1)
 
$
341

 
$
244

 
$
293

 
$
323

Impairment charge and other matters
 
$
26

 
$
(132
)
 
$
(37
)
 
$
(27
)
Operating income
 
$
183

 
$
239

 
$
191

 
$
202

Net Income
 
$
146

 
$
202

 
$
155

 
$
206

Net income attributable to noncontrolling interests
 
(1
)
 
—

 
(1
)
 
(1
)
Net income attributable to redeemable noncontrolling interests
 
—

 
—

 
—

 
(1
)
Net Income Attributable to Sunoco Logistics Partners L.P.
 
$
145

 
$
202

 
$
154

 
$
204

Less: General Partner's interest
 
(90
)
 
(98
)
 
(101
)
 
(104
)
Limited Partners' interest
 
$
55

 
$
104

 
$
53

 
$
100

Net Income (Loss) attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic
 
$
0.18

 
$
0.34

 
$
0.16

 
$
0.29

Net Income (Loss) attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted
 
$
0.18

 
$
0.34

 
$
0.16

 
$
0.29


 
 
1st Quarter
 
2nd Quarter
 
3rd Quarter
 
4th Quarter
 
 
(in millions, except per unit amounts)
2015
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
2,453

 
$
2,996

 
$
2,317

 
$
2,205

Affiliates
 
$
119

 
$
206

 
$
90

 
$
100

Gross profit (1)
 
$
214

 
$
326

 
$
325

 
$
312

Impairment charge and other matters
 
$
41

 
$
(100
)
 
$
103

 
$
118

Operating income
 
$
66

 
$
307

 
$
94

 
$
63

Net Income
 
$
37

 
$
277

 
$
57

 
$
26

Net income attributable to noncontrolling interests
 
(1
)
 
—

 
(1
)
 
(1
)
Net income attributable to redeemable noncontrolling interests
 
—

 
(1
)
 
—

 
—

Net Income Attributable to Sunoco Logistics Partners L.P.
 
$
36

 
$
276

 
$
56

 
$
25

Less: General Partner's interest
 
(60
)
 
(71
)
 
(74
)
 
(83
)
Limited Partners' interest
 
$
(24
)
 
$
205

 
$
(18
)
 
$
(58
)
Net Income (Loss) attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic
 
$
(0.10
)
 
$
0.83

 
$
(0.07
)
 
$
(0.21
)
Net Income (Loss) attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted
 
$
(0.10
)
 
$
0.83

 
$
(0.07
)
 
$
(0.21
)
(1) 
Gross profit equals sales and other operating revenue less cost of products sold and operating expenses.







102


20. Supplemental Condensed Consolidating Financial Information
The Partnership serves as guarantor of the senior notes. These guarantees are full and unconditional. For purposes of the following footnote, Sunoco Logistics Partners L.P. is referred to as "Parent Guarantor" and Sunoco Logistics Partners Operations L.P. is referred to as "Subsidiary Issuer." All other consolidated subsidiaries of the Partnership are collectively referred to as "Non-Guarantor Subsidiaries."
The following supplemental condensed consolidating financial information reflects the Parent Guarantor's separate accounts, the Subsidiary Issuer's separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent Guarantor's consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor's investments in its subsidiaries and the Subsidiary Issuer's investments in its subsidiaries are accounted for under the equity method of accounting.

103


Consolidating Statement of Comprehensive Income (Loss)
Year Ended December 31, 2016
(in millions)

 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Revenues
 
 
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
—

 
$
—

 
$
8,715

 
$
—

 
$
8,715

Affiliates
 
—

 
—

 
436

 
—

 
436

Total Revenues
 
—

 
—

 
9,151

 
—

 
9,151

Costs and Expenses
 
 
 
 
 
 
 
 
 
 
Cost of products sold
 
—

 
—

 
7,828

 
—

 
7,828

Operating expenses
 
—

 
—

 
122

 
—

 
122

Selling, general and administrative expenses
 
—

 
1

 
109

 
—

 
110

Depreciation and amortization expense
 
—

 
—

 
446

 
—

 
446

Impairment charge and other matters
 
—

 
—

 
(170
)
 
—

 
(170
)
Total Costs and Expenses
 
—

 
1

 
8,335

 
—

 
8,336

Operating Income (Loss)
 
—

 
(1
)
 
816

 
—

 
815

Net interest income (cost) to affiliates
 
—

 
7

 
(5
)
 
—

 
2

Other interest cost and debt expense, net
 
—

 
(275
)
 
5

 
—

 
(270
)
Capitalized interest
 
—

 
111

 
—

 
—

 
111

Gain on investment in affiliate
 
—

 
—

 
41

 
—

 
41

Other income
 
—

 
—

 
37

 
—

 
37

Equity in earnings of subsidiaries
 
705

 
863

 
—

 
(1,568
)
 
—

Income (Loss) Before Provision for Income Taxes
 
705

 
705

 
894

 
(1,568
)
 
736

Provision for income taxes
 
—

 
—

 
(27
)
 
—

 
(27
)
Net Income (Loss)
 
705

 
705

 
867

 
(1,568
)
 
709

Net income attributable to noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
Net income attributable to redeemable noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
705

 
$
705

 
$
863

 
$
(1,568
)
 
$
705

 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
705

 
$
705

 
$
867

 
$
(1,568
)
 
$
709

Comprehensive Income (Loss)
 
705

 
705

 
867

 
(1,568
)
 
709

Less: Comprehensive income attributable to noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
Less: Comprehensive income attributable to redeemable noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
705

 
$
705

 
$
863

 
$
(1,568
)
 
$
705


104


Consolidating Statement of Comprehensive Income (Loss)
Year Ended December 31, 2015
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Revenues
 
 
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
—

 
$
—

 
$
9,971

 
$
—

 
$
9,971

Affiliates
 
—

 
—

 
515

 
—

 
515

Total Revenues
 
—

 
—

 
10,486

 
—

 
10,486

Costs and Expenses
 
 
 
 
 
 
 
 
 
 
Cost of products sold
 
—

 
—

 
9,145

 
—

 
9,145

Operating expenses
 
—

 
—

 
164

 
—

 
164

Selling, general and administrative expenses
 
—

 
1

 
102

 
—

 
103

Depreciation and amortization expense
 
—

 
—

 
382

 
—

 
382

Impairment charge and other matters
 
—

 
—

 
162

 
—

 
162

Total Costs and Expenses
 
—

 
1

 
9,955

 
—

 
9,956

Operating Income (Loss)
 
—

 
(1
)
 
531

 
—

 
530

Other interest cost and debt expense, net
 
—

 
(209
)
 
(1
)
 
—

 
(210
)
Capitalized interest
 
—

 
76

 
—

 
—

 
76

Other income
 
—

 
—

 
22

 
—

 
22

Equity in earnings of subsidiaries
 
393

 
526

 
—

 
(919
)
 
—

Income (Loss) Before Provision for Income Taxes
 
393

 
392

 
552

 
(919
)
 
418

Provision for income taxes
 
—

 
—

 
(21
)
 
—

 
(21
)
Net Income (Loss)
 
393

 
392

 
531

 
(919
)
 
397

Net income attributable to noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
Net income attributable to redeemable noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
393

 
$
392

 
$
527

 
$
(919
)
 
$
393

 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
393

 
$
392

 
$
531

 
$
(919
)
 
$
397

Adjustment to affiliate's pension funded status
 
—

 
—

 
(1
)
 
—

 
(1
)
Other Comprehensive Income (Loss)
 
—

 
—

 
(1
)
 
—

 
(1
)
Comprehensive Income (Loss)
 
393

 
392

 
530

 
(919
)
 
396

Less: Comprehensive income attributable to noncontrolling interests
 
—

 
—

 
(3
)
 
—

 
(3
)
Less: Comprehensive income attributable to redeemable noncontrolling interests
 
—

 
—

 
(1
)
 
—

 
(1
)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
393

 
$
392

 
$
526

 
$
(919
)
 
$
392


105


Consolidating Statement of Comprehensive Income (Loss)
Year Ended December 31, 2014
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Revenues
 
 
 
 
 
 
 
 
 
 
Sales and other operating revenue:
 
 
 
 
 
 
 
 
 
 
Unaffiliated customers
 
$
—

 
$
—

 
$
17,018

 
$
—

 
$
17,018

Affiliates
 
—

 
—

 
1,070

 
—

 
1,070

Total Revenues
 
—

 
—

 
18,088

 
—

 
18,088

Costs and Expenses
 
 
 
 
 
 
 
 
 
 
Cost of products sold
 
—

 
—

 
16,877

 
—

 
16,877

Operating expenses
 
—

 
—

 
172

 
—

 
172

Selling, general and administrative expenses
 
—

 
—

 
118

 
—

 
118

Depreciation and amortization expense
 
—

 
—

 
296

 
—

 
296

Impairment charge and other matters
 
—

 
—

 
258

 
—

 
258

Total Costs and Expenses
 
—

 
—

 
17,721

 
—

 
17,721

Operating Income
 
—

 
—

 
367

 
—

 
367

Net interest income (cost) to affiliates
 
—

 
5

 
(4
)
 
—

 
1

Other interest cost and debt expense, net
 
—

 
(146
)
 
—

 
—

 
(146
)
Capitalized interest
 
—

 
78

 
—

 
—

 
78

Other income
 
—

 
—

 
25

 
—

 
25

Equity in earnings of subsidiaries
 
291

 
354

 
—

 
(645
)
 
—

Income (Loss) Before Provision for Income Taxes
 
291

 
291

 
388

 
(645
)
 
325

Provision for income taxes
 
—

 
—

 
(25
)
 
—

 
(25
)
Net Income (Loss)
 
291

 
291

 
363

 
(645
)
 
300

Net income attributable to noncontrolling interests
 
—

 
—

 
(9
)
 
—

 
(9
)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
291

 
$
291

 
$
354

 
$
(645
)
 
$
291

 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
291

 
$
291

 
$
363

 
$
(645
)
 
$
300

Adjustment to affiliate's pension funded status
 
—

 
—

 
1

 
—

 
1

Other Comprehensive Income (Loss)
 
—

 
—

 
1

 
—

 
1

Comprehensive Income (Loss)
 
291

 
291

 
364

 
(645
)
 
301

Less: Comprehensive income attributable to noncontrolling interests
 
—

 
—

 
(9
)
 
—

 
(9
)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.
 
$
291

 
$
291

 
$
355

 
$
(645
)
 
$
292


 


106


Consolidating Balance Sheet
December 31, 2016
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
—

 
$
41

 
$
—

 
$
—

 
$
41

Accounts receivable, net
 
—

 
—

 
1,555

 
—

 
1,555

Accounts receivable, affiliated companies
 
—

 
—

 
44

 
—

 
44

Inventories
 
—

 
—

 
934

 
—

 
934

Note receivable, affiliated companies
 
—

 
—

 
301

 
—

 
301

Other current assets
 
—

 
2

 
29

 
—

 
31

Total Current Assets
 
—

 
43

 
2,863

 
—

 
2,906

Properties, plants and equipment, net
 
—

 
—

 
12,324

 
—

 
12,324

Investment in affiliates
 
7,199

 
10,664

 
952

 
(17,863
)
 
952

Goodwill
 
—

 
—

 
1,609

 
—

 
1,609

Intangible assets, net
 
—

 
—

 
977

 
—

 
977

Other assets
 
—

 
5

 
76

 
—

 
81

Total Assets
 
$
7,199

 
$
10,712

 
$
18,801

 
$
(17,863
)
 
$
18,849

Liabilities and Equity
 
 
 
 
 
 
 
 
 
 
Accounts payable
 
$
—

 
$
—

 
$
1,750

 
$
—

 
$
1,750

Accounts payable, affiliated companies
 
—

 
4

 
59

 
—

 
63

Accrued liabilities
 
—

 
49

 
238

 
—

 
287

Accrued taxes payable
 
—

 
—

 
38

 
—

 
38

Intercompany
 
(1,761
)
 
(3,853
)
 
5,614

 
—

 
—

Total Current Liabilities
 
(1,761
)
 
(3,800
)
 
7,699

 
—

 
2,138

Long-term debt
 
—

 
7,313

 
—

 
—

 
7,313

Other deferred credits and liabilities
 
—

 
—

 
133

 
—

 
133

Deferred income taxes
 
—

 
—

 
257

 
—

 
257

Total Liabilities
 
(1,761
)
 
3,513

 
8,089

 
—

 
9,841

Redeemable noncontrolling interests
 
—

 
—

 
15

 
—

 
15

Redeemable Limited Partners' interests
 
300

 
—

 
—

 
—

 
300

Equity
 
 
 
 
 
 
 
 
 
 
Sunoco Logistics Partners L.P. equity
 
8,660

 
7,199

 
10,664

 
(17,863
)
 
8,660

Noncontrolling interests
 
—

 
—

 
33

 
—

 
33

Total Equity
 
8,660

 
7,199

 
10,697

 
(17,863
)
 
8,693

Total Liabilities and Equity
 
$
7,199

 
$
10,712

 
$
18,801

 
$
(17,863
)
 
$
18,849


107


Consolidating Balance Sheet
December 31, 2015
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
—

 
$
37

 
$
—

 
$
—

 
$
37

Accounts receivable, net
 
—

 
—

 
1,165

 
—

 
1,165

Accounts receivable, affiliated companies
 
—

 
3

 
17

 
—

 
20

Inventories
 
—

 
—

 
607

 
—

 
607

Other current assets
 
—

 
—

 
19

 
—

 
19

Total Current Assets
 
—

 
40

 
1,808

 
—

 
1,848

Properties, plants and equipment, net
 
—

 
—

 
10,692

 
—

 
10,692

Investment in affiliates
 
6,488

 
9,692

 
802

 
(16,180
)
 
802

Goodwill
 
—

 
—

 
1,358

 
—

 
1,358

Intangible assets, net
 
—

 
—

 
718

 
—

 
718

Other assets
 
—

 
6

 
65

 
—

 
71

Total Assets
 
$
6,488

 
$
9,738

 
$
15,443

 
$
(16,180
)
 
$
15,489

Liabilities and Equity
 
 
 
 
 
 
 
 
 
 
Accounts payable
 
$
—

 
$
1

 
$
1,250

 
$
—

 
$
1,251

Accounts payable, affiliated companies
 
—

 
—

 
39

 
—

 
39

Accrued liabilities
 
1

 
66

 
262

 
—

 
329

Accrued taxes payable
 
—

 
—

 
44

 
—

 
44

Intercompany
 
(1,320
)
 
(2,408
)
 
3,728

 
—

 
—

Total Current Liabilities
 
(1,319
)
 
(2,341
)
 
5,323

 
—

 
1,663

Long-term debt
 
—

 
5,591

 
—

 
—

 
5,591

Other deferred credits and liabilities
 
—

 
—

 
125

 
—

 
125

Deferred income taxes
 
—

 
—

 
254

 
—

 
254

Total Liabilities
 
(1,319
)
 
3,250

 
5,702

 
—

 
7,633

Redeemable noncontrolling interests
 
—

 
—

 
15

 
—

 
15

Redeemable Limited Partners' interests
 
286

 
—

 
—

 
—

 
286

Equity
 
 
 
 
 
 
 
 
 
 
Sunoco Logistics Partners L.P. equity
 
7,521

 
6,488

 
9,692

 
(16,180
)
 
7,521

Noncontrolling interests
 
—

 
—

 
34

 
—

 
34

Total Equity
 
7,521

 
6,488

 
9,726

 
(16,180
)
 
7,555

Total Liabilities and Equity
 
$
6,488

 
$
9,738

 
$
15,443

 
$
(16,180
)
 
$
15,489


108


Consolidating Statement of Cash Flows
Year Ended December 31, 2016
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Net Cash Flows from Operating Activities
 
$
704

 
$
676

 
$
1,076

 
$
(1,568
)
 
$
888

Cash Flows from Investing Activities:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
—

 
—

 
(1,949
)
 
—

 
(1,949
)
Acquisitions
 
—

 

 
(786
)
 
—

 
(786
)
Change in note receivable, affiliated companies
 
—

 
—

 
(301
)
 
—

 
(301
)
Change in long-term note receivable
 
—

 
—

 
(2
)
 
—

 
(2
)
Intercompany
 
(1,126
)
 
(2,401
)
 
1,959

 
1,568

 
—

Net cash provided by (used in) investing activities
 
(1,126
)
 
(2,401
)
 
(1,079
)
 
1,568

 
(3,038
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
 
 
 
 
Distributions paid to limited and general partners
 
(961
)
 
—

 
—

 
—

 
(961
)
Distributions paid to noncontrolling interests
 
(5
)
 
—

 
—

 
—

 
(5
)
Net proceeds from issuance of limited partner units
 
1,388

 
—

 
—

 
—

 
1,388

Payments of statutory withholding on net issuance of limited partner units under LTIP
 
—

 
—

 
(4
)
 
—

 
(4
)
Repayments under credit facilities
 
—

 
(5,840
)
 
—

 
—

 
(5,840
)
Borrowings under credit facilities
 
—

 
7,200

 
—

 
—

 
7,200

Net proceeds from issuance of long-term debt
 
—

 
544

 
—

 
—

 
544

Repayments of senior notes
 
—

 
(175
)
 
—

 
—

 
(175
)
Contributions attributable to acquisition from affiliate
 
—

 
—

 
7

 
—

 
7

Net cash provided by financing activities
 
422

 
1,729

 
3

 
—

 
2,154

Net change in cash and cash equivalents
 
—

 
4

 
—

 
—

 
4

Cash and cash equivalents at beginning of period
 
—

 
37

 
—

 
—

 
37

Cash and cash equivalents at end of period
 
$
—

 
$
41

 
$
—

 
$
—

 
$
41


109


Consolidating Statement of Cash Flows
Year Ended December 31, 2015
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Net Cash Flows from Operating Activities
 
$
393

 
$
388

 
$
736

 
$
(919
)
 
$
598

Cash Flows from Investing Activities:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
—

 
—

 
(2,706
)
 
—

 
(2,706
)
Acquisitions
 
—

 

 
(131
)
 
—

 
(131
)
Change in long-term note receivable
 
—

 
—

 
(17
)
 
—

 
(17
)
Intercompany
 
(1,223
)
 
(1,814
)
 
2,118

 
919

 
—

Net cash provided by (used in) investing activities
 
(1,223
)
 
(1,814
)
 
(736
)
 
919

 
(2,854
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
 
 
 
 
Distributions paid to limited and general partners
 
(686
)
 
—

 
—

 
—

 
(686
)
Distributions paid to noncontrolling interests
 
(3
)
 
—

 
—

 
—

 
(3
)
Net proceeds from issuance of limited partner units
 
1,519

 
 
 
 
 
 
 
1,519

Payments of statutory withholding on net issuance of limited partner units under LTIP
 
—

 
—

 
(11
)
 
—

 
(11
)
Repayments under credit facilities
 
—

 
(3,662
)
 
—

 
—

 
(3,662
)
Borrowings under credit facilities
 
—

 
4,039

 
—

 
—

 
4,039

Net proceeds from issuance of long-term debt
 
—

 
991

 
—

 
—

 
991

Contributions attributable to acquisition from affiliate
 
—

 
—

 
11

 
—

 
11

Other
 
—

 
(6
)
 
—

 
—

 
(6
)
Net cash provided by financing activities
 
830

 
1,362

 
—

 
—

 
2,192

Net change in cash and cash equivalents
 
—

 
(64
)
 
—

 
—

 
(64
)
Cash and cash equivalents at beginning of period
 
—

 
101

 
—

 
—

 
101

Cash and cash equivalents at end of period
 
$
—

 
$
37

 
$
—

 
$
—

 
$
37


110


Consolidating Statement of Cash Flows
Year Ended December 31, 2014
(in millions)
 
 
 
Parent
Guarantor
 
Subsidiary
Issuer
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Total
Net Cash Flows from Operating Activities
 
$
290

 
$
271

 
$
649

 
$
(644
)
 
$
566

Cash Flows from Investing Activities:
 
 
 
 
 
 
 
 
 
 
Capital expenditures
 
—

 
—

 
(2,416
)
 
—

 
(2,416
)
Acquisitions
 
—

 
—

 
(433
)
 
—

 
(433
)
Change in long-term note receivable
 
—

 
—

 
(17
)
 
—

 
(17
)
Intercompany
 
(876
)
 
(2,012
)
 
2,244

 
644

 
—

Net cash provided by (used in) investing activities
 
(876
)
 
(2,012
)
 
(622
)
 
644

 
(2,866
)
Cash Flows from Financing Activities:
 
 
 
 
 
 
 
 
 
 
Distributions paid to limited and general partners
 
(468
)
 
—

 
—

 
—

 
(468
)
Distributions paid to noncontrolling interests
 
(4
)
 
—

 
—

 
—

 
(4
)
Contributions from general partner
 
2

 
—

 
—

 
—

 
2

Net proceeds from issuance of limited partner units
 
839

 
—

 
—

 
—

 
839

Payments of statutory withholding on net issuance of limited partner units under LTIP
 
—

 
—

 
(9
)
 
—

 
(9
)
Repayments under credit facilities
 
—

 
(2,845
)
 
—

 
—

 
(2,845
)
Borrowings under credit facilities
 
—

 
2,795

 
—

 
—

 
2,795

Net proceeds from issuance of long-term debt
 
—

 
1,976

 
—

 
—

 
1,976

Repayment of senior notes
 
—

 
(175
)
 
—

 
—

 
(175
)
Advances to affiliated companies, net
 
217

 
79

 
(57
)
 
—

 
239

Contributions attributable to acquisition from affiliate
 
—

 
—

 
12

 
—

 
12

Net cash provided by (used in) financing activities
 
586

 
1,830

 
(54
)
 
—

 
2,362

Net change in cash and cash equivalents
 
—

 
89

 
(27
)
 
—

 
62

Cash and cash equivalents at beginning of period
 
—

 
12

 
27

 
—

 
39

Cash and cash equivalents at end of period
 
$
—

 
$
101

 
$
—

 
$
—

 
$
101




111


ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
 
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to ensure that information required to be disclosed in the Partnership's reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified by the rules and forms of the Securities and Exchange Commission. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the Partnership's reports under the Exchange Act is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer and Treasurer of Sunoco Partners LLC (the Partnership's general partner), as appropriate, to allow timely decisions regarding required disclosure.
As of December 31, 2016, the Partnership carried out an evaluation, under the supervision and with the participation of management of the general partner (including the President and Chief Executive Officer and the Chief Financial Officer and Treasurer), of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the general partner's President and Chief Executive Officer and Chief Financial Officer and Treasurer concluded that the Partnership's disclosure controls and procedures were effective.
Management of the general partner is responsible for establishing, maintaining, and annually assessing internal control over the Partnership's financial reporting. A report by the general partner's management, assessing the effectiveness of the Partnership's internal control over financial reporting, appears under Item 8. "Financial Statements and Supplementary Data" of this report. Grant Thornton LLP, the Partnership's independent registered public accounting firm, has issued an attestation report on the Partnership's internal control over financial reporting, that also appears under Item 8. of this report.
No change in the Partnership's internal control over financial reporting has occurred during the fiscal quarter ended December 31, 2016 that has materially affected, or that is reasonably likely to materially affect, the Partnership's internal control over financial reporting.
 
ITEM 9B.
OTHER INFORMATION
None.


112



PART III
 
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our general partner, Sunoco Partners LLC, a Pennsylvania limited liability company, manages our operations and activities. The membership interests in our general partner are owned 99.9 percent by Energy Transfer Partners, L.P., a Delaware limited partnership ("ETP"), and 0.1 percent by ETE Common Holdings, LLC, a Delaware limited liability company ("ETE Holdings").
As the sole members of our general partner, ETP and ETE Holdings are entitled under the limited liability company agreement of Sunoco Partners LLC to appoint all of the directors of our general partner. Our general partner's limited liability company agreement provides that our general partner's Board of Directors (the "Board") shall consist of between three and twelve persons, at least three of whom are required to qualify as independent directors. As of December 31, 2016, the Board consisted of six persons, three of whom qualify as "independent" under the listing standards of the New York Stock Exchange ("NYSE") and our governance guidelines. The directors who qualify as "independent" under the NYSE's listing standards and our governance guidelines are Steven R. Anderson, Scott A. Angelle and Basil Leon Bray. Prior to his resignation on December 31, 2016, James R. ("Rick") Perry served on the Board and qualified as "independent" under the NYSE's listing standards and our governance guidelines.
As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that ETP and ETE Holdings have appointed as directors individuals with experience, skills and qualifications relevant to our business, such as experience in energy or related industries, experience with financial markets, expertise in crude oil, natural gas liquids and refined products operations or finance, and a history of service in senior leadership positions.
The Board held six (four regular and two special) meetings during 2016. The Board has established standing committees to consider designated matters. The standing committees of the Board are: the Audit Committee, the Compensation Committee and the Conflicts Committee. The listing standards of the NYSE do not require boards of directors of publicly-traded master limited partnerships to be composed of a majority of independent directors nor are they required to have a standing nominating or compensation committee. Notwithstanding, the Board has elected to have a standing compensation committee. The Board has adopted governance guidelines for the Board and charters for each of the Audit, Compensation, and Conflicts Committees.
Audit Committee
The Board has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934. The Board appoints persons who are independent under the NYSE's standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board has determined that based on relevant experience, Audit Committee member Basil Leon Bray qualified as an audit committee financial expert during 2016. A description of the qualifications of Mr. Bray may be found elsewhere in this Item 10 under "Directors and Executive Officers of Sunoco Partners LLC (our General Partner)."
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board relating to our audited financial statements. The Audit Committee periodically recommends to the Board any changes or modifications to its charter that may be required or desired. The Audit Committee has received

113


written disclosures and the letter from Grant Thornton LLP ("Grant Thornton"), required by applicable requirements of the Audit Committee concerning independence, and has discussed with Grant Thornton the firm's independence.
The current members of the Audit Committee are: Basil Leon Bray (Chairman), Steven R. Anderson and Scott A. Angelle. The Audit Committee met four times during 2016. In conjunction with its regular meetings, the Audit Committee also meets in executive session without members of management present. Mr. Bray, as Chairman of the Audit Committee, leads these executive session meetings, the purpose of which is to promote open and candid discussion among the independent directors.
Compensation Committee 
The Compensation Committee establishes standards and makes recommendations concerning the compensation of the officers and directors of our general partner. In addition, the Compensation Committee determines and establishes the standards for any awards to the employees and officers of our general partner under the equity compensation plans, including the requirements pertaining to the vesting of any such awards. The current members of the Compensation Committee are: Scott A. Angelle (Chairman), Marshall S. ("Mackie") McCrea, III, Steven R. Anderson, Basil Leon Bray and Michael J. Hennigan. Prior to his resignation on December 31, 2016, James R. ("Rick") Perry was also a member of the Compensation Committee. Since Mr. McCrea is Group Chief Operating Officer and Chief Commercial Officer of LE GP, LLC (hereinafter referred to as "ETE's general partner"), the general partner of Energy Transfer Equity, L.P. ("ETE"), and Mr. Hennigan is also an officer of our general partner, they each recuse themselves from Compensation Committee decisions relating to equity compensation awards (including awards under the Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated (the "LTIP")) to executive officers of the general partner. Messrs. McCrea and Hennigan also recuse themselves from Compensation Committee decisions relating to their own compensation or equity compensation awards, as applicable. The Compensation Committee met two times during 2016.
Conflicts Committee
Our partnership agreement provides that the Board may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by our general partner is fair and reasonable to us and our unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to us to determine if the transaction presents a conflict of interest between ETP and/or its affiliates and us and determines whether the resolution or transaction is fair and reasonable to us. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us and not a breach by the general partner or the Board of any duties they may owe to the members of our general partner or our unitholders. The members of the Conflicts Committee consist of certain directors of our general partner who are not also executive officers of our general partner or its affiliates. The current members of the Conflicts Committee are: Steven R. Anderson (Chairman), Scott A. Angelle and Basil Leon Bray. The Conflicts Committee met nineteen times during 2016.
Corporate Governance
Our general partner has adopted a Code of Ethics for Senior Officers, which applies to the principal executive officer, the principal financial officer, the principal accounting officer, the treasurer and persons performing similar functions for our general partner and its subsidiaries. In addition, our general partner has adopted a Code of Business Conduct and Ethics, which applies to all directors, officers and employees. The Code of Business Conduct and Ethics addresses ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications, and prompt internal reporting of violations. In accordance with the disclosure requirements of applicable law or regulation, we intend to disclose any amendment to, or waiver of, any provision of these codes, on our website at www.sunocologistics.com, via a press release, or under Item 5.05 of a Current Report on Form 8-K.
We make available, free of charge within the "Investors - Corporate Governance" section of our website at www.sunocologistics.com, and in print to any unitholder who so requests, the Code of Ethics for Senior Officers, the Code of Business Conduct and Ethics, the Audit Committee Charter, the Compensation Committee Charter, the Conflicts Committee Charter, the Corporate Governance Guidelines and our limited partnership agreement. The information contained on, or connected to, our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with, or furnish to, the Securities and Exchange Commission ("SEC").


114


Communication with the Board of Directors
In order that interested parties may be able to make their concerns known to the independent directors, our unitholders and other interested parties may communicate directly with the Board, with the independent directors as a group, or with any director or committee chairperson by writing to such parties in care of Kathleen Shea-Ballay, Senior Vice President, General Counsel and Secretary, Sunoco Partners LLC, 3807 West Chester Pike, Newtown Square, PA 19073. Communications may be submitted confidentially and anonymously. Under certain circumstances, the general partner or we may be required by law to disclose the information or identity of the person submitting the communication.
Communications addressed to the Board generally will be forwarded either to the appropriate committee chairperson or to all directors. Certain concerns communicated to the Board also may be referred to the general partner's internal auditor or its General Counsel, in accordance with the general partner's regular procedures for addressing such concerns. The chairman of the general partner's Audit Committee, or the chairman of the Board, may direct that certain concerns be presented to the Audit Committee, or to the full Board, or that such concerns otherwise receive special treatment, including retention of external counsel or other advisors. No material actions were taken by the Board because of communications from unitholders or others received during 2016.
Directors and Executive Officers of Sunoco Partners LLC (our General Partner)
Our directors are elected by ETP and ETE Holdings. Our executive officers are appointed by the Board.
The following table shows information for the current directors and executive officers of Sunoco Partners LLC, our general partner, as of the date of this filing. Executive officers and directors are each elected for one-year terms or until their successors are elected and qualified.
Name
 
Age
 
Position with the General Partner
Marshall S. ("Mackie") McCrea, III
 
57

 
Chairman of the Board
Michael J. Hennigan
 
57

 
Director, President and Chief Executive Officer
Steven R. Anderson
 
67

 
Director
Scott A. Angelle
 
55

 
Director
Basil Leon Bray
 
72

 
Director
Thomas P. Mason
 
60

 
Director
Kurt A. Lauterbach
 
61

 
Senior Vice President, Lease Acquisition and Marketing
David R. Chalson
 
65

 
Senior Vice President, Operations
Michael W. Slough
 
60

 
Senior Vice President, Engineering, Construction & Procurement
Kathleen Shea-Ballay
 
51

 
Senior Vice President, General Counsel and Secretary
Peter J. Gvazdauskas
 
38

 
Chief Financial Officer and Treasurer
Michael D. Galtman
 
42

 
Controller and Chief Accounting Officer
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
Mr. McCrea was elected as Chairman of the Board in October 2012. In addition to serving as Chairman of the Board, he serves as a director of ETE's general partner and as a director of Energy Transfer Partners, L.L.C. (hereinafter referred to as "ETP's general partner"), the general partner of ETP's general partner, both since 2009. He is the Group Chief Operating Officer and Chief Commercial Officer of ETE's general partner, and has served in those capacities since November 2015. Prior to that, he served as President and Chief Operating Officer of ETP's general partner from June 2008 to November 2015 and as President - Midstream of ETP's general partner from March 2007 to June 2008. Previously he served as the Senior Vice President - Commercial Development since the combination of the operations of La Grange Acquisition, L.P., which does business under the name of Energy Transfer Company ("ETC OLP"), and Heritage Operating, L.P. ("HOLP") in January 2004. In March 2005, Mr. McCrea was named president of ETC OLP. Prior to the combination of the operations of ETC OLP and HOLP, Mr. McCrea served as Senior Vice President - Business Development and Producer Services of the general partner of ETC OLP and ET Company I, Ltd., having served in that capacity since 1997. Mr. McCrea has extensive project development and operational experience, and is able to assist the Board in creating and executing the Partnership's strategic plan.




115


Mr. Hennigan was elected to the Board in April 2010. He was elected President and Chief Executive Officer, effective March 1, 2012. Prior to that, he was President and Chief Operating Officer from July 2010 until March 2012. From May 2009 until July 2010, Mr. Hennigan served as Vice President, Business Development. Prior to joining our general partner, he was employed in the following positions at Sunoco, Inc.: Senior Vice President, Business Improvement from October 2008 to May 2009; and Senior Vice President, Supply, Trading, Sales and Transportation from February 2006 to October 2008. Mr. Hennigan has served as a member of the board of directors of Niska Gas Storage Partners LLC since September 10, 2014.
Mr. Anderson was elected to the Board in October 2012. Mr. Anderson began his career in the energy business in the early 1970's with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of the midstream business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer, in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and currently serves as a member of the boards of directors of the St. John Health System and Saint Simeon's Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations.
Mr. Angelle was elected to the Board in December 2012. He is an elected member of the Louisiana Public Service Commission, a five-person regulatory body. Beginning in May 2010, Mr. Angelle served for six months as the interim Lieutenant Governor of Louisiana. During the period from 2004 to August 2012, with the exception of his service as Lieutenant Governor, he served as the Secretary of the Louisiana Department of Natural Resources. Since 2012, Mr. Angelle also has represented Louisiana's Third Congressional District on the Board of Supervisors of Louisiana State University. Mr. Angelle also has a career in strategic planning and petroleum land management and is the principal in the firm Planning Strategies, LLC. Mr. Angelle is a member of the board of directors of Farmers Merchants Bank in Breaux Bridge, Louisiana.
Mr. Bray was elected to the Board in October 2012. Currently, Mr. Bray is the Chief Executive Officer of Energy Strategies, Inc., an energy consulting firm headquartered in Tulsa, Oklahoma. He has held this position since 1994. Previously, he held various management positions with Phillips Petroleum Co., Endevco, Inc., and Anadarko Petroleum Corp. Mr. Bray also was Co-Founder and President of Resource Energy Services, LLC until its sale in 1996.
Mr. Mason was elected to the Board in October 2012. He is the Executive Vice President and General Counsel of ETE's general partner, and has served in that capacity since December 2015. Prior to that, Mr. Mason served as the Senior Vice President, General Counsel and Secretary of ETP's general partner since April 2012, as the Vice President, General Counsel and Secretary of ETP's general partner since June 2008 and as General Counsel and Secretary of ETP's general partner since February 2007. Prior to joining ETP, he was a partner in the Houston office of Vinson & Elkins LLP. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years.
Mr. Lauterbach was elected Senior Vice President, Lease Acquisition and Marketing in January 2013. Prior to that, he was Vice President, Lease Acquisition and Marketing from October 2010 to January 2013. Mr. Lauterbach also served as Manager of Marketing and Trading-Lease Acquisition from June 2008 to October 2010.
Mr. Chalson was elected Senior Vice President, Operations in January 2013. Prior to that, he was Vice President, Operations from July 2012 to January 2013. From 2007 to 2012, Mr. Chalson served as Manager, Oil Movements.
Mr. Slough was elected Senior Vice President, Engineering, Construction & Procurement in January 2013. Mr. Slough had been Vice President, Engineering, Construction & Procurement of the Partnership since 2012. Prior to that, he was Director of Engineering & Construction of the Partnership from 2010 to 2012. From 2006 to 2010, he was Venture Manager at Sunoco, Inc.
Ms. Shea-Ballay was elected Senior Vice President, General Counsel and Secretary in January 2013. Prior to that, she was Vice President, General Counsel and Secretary from June 2010 to January 2013. Ms. Shea-Ballay served as Assistant General Counsel and Chief Counsel for Commercial Transactions for Sunoco, Inc. from April 2005 until June 2010. Prior to joining Sunoco, Inc., Ms. Shea-Ballay was a partner at Pepper Hamilton LLP, a law firm in Philadelphia, Pennsylvania.
Mr. Gvazdauskas was elected Chief Financial Officer in March 2015 and has served as Treasurer since January 2012. He previously served as Vice President, Finance since January 2012. Prior to that, he had been Vice President, Finance since April 2010. From June 2008 to March 2010, he served as Manager of Corporate Finance of Sunoco, Inc.; from December 2007 to May 2008, he was Manager of Special Projects at Sunoco, Inc.; and from November 2005 to November 2007, he was Controller of SunCoke Energy, Inc.
Mr. Galtman was elected Controller and Chief Accounting Officer in July 2008. From June 2007 to July 2008, he served as Manager of Financial Planning and Analysis.



116


SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2016, except as set forth below:
•
late filing of a Form 4 for Mr. Bray; and
•
late filing of a Form 4 for Mr. Lauterbach.


117



ITEM 11.
EXECUTIVE COMPENSATION
We do not have any employees. Instead, we are managed by our general partner, and the executive officers of our general partner perform all of our management functions. We pay 100 percent of the compensation of the executive officers and employees of our general partner. The executive officers and employees of our general partner also participate in employee benefit plans and arrangements sponsored by our general partner or its affiliates.

COMPENSATION DISCUSSION AND ANALYSIS
Named Executive Officers
This Compensation Discussion and Analysis ("CD&A") is focused on the total compensation of the named executive officers of our general partner as set forth below. The CD&A is required to disclose compensation information for individuals that are deemed to be our Named Executive Officers ("NEOs") for the 2016 year. In accordance with the SEC's compensation disclosure rules, the identity of an NEO is determined on December 31 of the year to which the disclosures relate, despite any changes to executive roles that may occur following the end of the applicable calendar year. During 2016, the following individuals were employees of our general partner and rendered their services solely to us.
Throughout the CD&A discussion, the following individuals are referred to as the Named Executive Officers ("NEOs") and are included in the Summary Compensation Table:
Michael J. Hennigan - President and Chief Executive Officer
Peter J. Gvazdauskas - Chief Financial Officer and Treasurer
David R. Chalson - Senior Vice President, Operations
Kurt A. Lauterbach - Senior Vice President, Lease Acquisition and Marketing
Kathleen Shea-Ballay - Senior Vice President, General Counsel and Secretary     
Compensation Philosophy and Objectives
Our compensation philosophy and objectives are substantially consistent with those set by ETE and ETP and are based on the premise that a significant portion of each executive's total compensation should be incentive-based or "at-risk" compensation. We also share ETP's philosophy that executives' total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our general partner, in accordance with guidance established by ETP, seeks a total compensation program that provides the NEOs with a slightly below the median market annual base compensation rate (i.e., approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both targeted to pay out at approximately the top-quartile of market. Our general partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership's financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of our NEOs to the success of the Partnership and the achievement of the annual financial performance objectives, and (ii) the annual grant of time-based restricted unit awards under the LTIP, which awards are intended to provide a long-term incentive and retentive value to our key employees to focus their efforts on increasing the market price of our publicly traded units and to increase the cash distribution we pay to our unitholders.
During 2016, the compensation for our executive officers, including our NEOs, was determined by our general partner's Compensation Committee. Our compensation program is structured to provide the following benefits:
•
reward executives with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities, yielding a total compensation package approaching the top-quartile of the market;
•
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;
•
motivate executive officers and key employees to achieve strong financial and operational performance;
•
emphasize performance-based or "at-risk" compensation; and
•
reward individual performance.

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Compensation Methodology
Our general partner's Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual bonuses and long-term incentive compensation for our executive officers. The Compensation Committee also considers individual performance, levels of responsibility, skills and experience. For our 2016 compensation packages, our compensation methodology for the NEOs was substantially similar to that of ETP.
Periodically, the compensation committees of ETE's and/or ETP's general partner engage a third-party consultant to provide market information for compensation levels at peer companies in order to assist the Compensation Committee in its determination of compensation levels for our executive officers. The engagement of a third-party consultant typically occurs every two years. Most recently, Longnecker & Associates ("Longnecker") was engaged to evaluate the market competitiveness of total compensation levels of a number of officers of ETE, ETP and our Partnership and to provide market information with respect to compensation of certain executives during the year ended December 31, 2015. The Compensation Committee determined that the information received by Longnecker during the 2015 year was still relevant and applicable to the 2016 compensation program, therefore it utilized the information previously provided by Longnecker to ensure that the total compensation of our NEOs is both competitive with the market information received and consistent with our compensation philosophy. In particular, the 2015 review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our NEOs; (ii) assist in the determination of appropriate compensation levels for senior management, including our NEOs; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. In respect of the Partnership, we were reviewed by Longnecker through various metrics in order to recognize that the Partnership's structure is unique given that (i) in certain respects, the Partnership operates as significant operational division of ETP; (ii) the Partnership receives certain shared-service support from ETE and ETP; and (iii) in other functions, the Partnership operates as an independent publicly-traded organization. As such, Longnecker reviewed certain of the executives, including the NEOs, in their specific functions to determine the appropriate comparison technique. In all circumstances, Longnecker considered our annual revenues and market capitalization levels in its analysis.
In conducting its review with respect to executives that were considered to have roles consistent with those of an executive at an independent publicly-traded entity, Longnecker also worked with us to identify a "peer group" of companies in the energy industry that most closely reflect our profile in terms of revenues, assets and market value as well as compete with us for talent at the senior management level. The identified companies included:
Ÿ
Buckeye Partners, L.P.
Ÿ
PBF Energy Inc.
Ÿ
Enbridge Energy Partners, L.P.
Ÿ
Plains All American Pipeline, L.P.
Ÿ
HollyFrontier Corporation
Ÿ
Spectra Energy Corp
Ÿ
MarkWest Energy Partners, L.P.
Ÿ
Targa Resources Corp.
Ÿ
NGL Energy Partners LP
Ÿ
Tesoro Corporation
Ÿ
ONEOK Inc.
 
 
The compensation analysis provided by Longnecker covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives for certain companies in the oil and gas industry.
For 2016, our general partner's Compensation Committee continued to use the results of the 2015 Longnecker compensation analysis, adjusted to account for general inflation and information obtained from other sources, such as 2016 third-party survey results, in its determination of compensation levels for executives, including the named executive officers. Longnecker did not provide any non-executive compensation services for the Partnership during 2016.
In addition to the information received as a result of a periodic engagement of a third-party consultant, the Compensation Committee also utilizes information obtained from other sources, such as annual third-party surveys, for comparison purposes in its determination of compensation levels for our NEOs.


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Elements of Compensation
Compensation references in this section of the CD&A apply to our NEOs and executive officers.
•
Base Salary: Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility, and results achieved). The salaries of the NEOs are reviewed on an annual basis. With respect to the 2016 year, salary increases were generally discussed and approved by the Compensation Committee in July 2016, although the Compensation Committee provided for an increase in Mr. Gvazdauskas' base salary in January 2016 as well. As discussed above, the base salaries of the NEOs are targeted to yield an annual base salary slightly below median level of market (i.e., approximately the 40th percentile of market) and are determined by the Compensation Committee after taking into account the recommendations of our President and Chief Executive Officer. Base salaries also are influenced by internal pay equity (fair and consistent application of compensation practices). At the NEO level, the balance of compensation is weighted toward pay-at-risk compensation (annual bonuses and long-term incentives). The table below shows the base salaries determined for the NEOs with respect to the 2016 year (following all 2016 increases), as well as the base salaries in effect for the NEOs at the end of the 2015 year for comparison purposes:
Name
 
2016 Base Salary
 
2015 Base Salary
Mr. Hennigan
 
$637,500
 
$625,000
Mr. Gvazdauskas
 
$320,000
 
$300,000
Mr. Chalson
 
$285,565
 
$279,965
Mr. Lauterbach
 
$335,958
 
$329,371
Ms. Shea-Ballay
 
$341,700
 
$335,000
With the exception of Mr. Gvazdauskas, whose increase reflected an additional step towards achieving the benchmark contained in the market analysis by Longnecker, the 2 percent increase to each of the other NEOs base salary reflects a base salary increase consistent with the 2 percent annual merit increase pool established for all employees of the Partnership and ETP and its and their affiliates for 2016 by the respective compensation committees.
•
Annual Bonuses: In addition to base salary, the Compensation Committee makes a determination whether to award our NEOs discretionary annual cash bonuses following the end of the year. Discretionary bonuses, if awarded, are intended to reward our NEOs for the achievement of financial performance objectives during the year for which the bonuses are awarded in light of the contribution of each individual to our profitability and success during such year. The Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and the Compensation Committee does not utilize any formulaic approach to determine annual bonuses.
For 2016, annual bonuses were determined under the Sunoco Partners LLC Amended and Restated Annual Short-Term Incentive Bonus Plan (the "ASIP"). Under the ASIP, the Compensation Committee's evaluation of performance and determination of an overall available bonus pool is based on the Partnership's internal earnings target generally based on targeted EBITDA (the "Earnings Target") budget and the performance of each department compared to the applicable departmental budget (with such performance measured based on the specific dollar amount of general and administrative expenses set for each department). The two performance criteria are weighted 75 percent on internal Earnings Target budget criteria and 25 percent on internal department financial budget criteria. Internal Earnings Target is the primary performance factor in determining annual bonuses, while internal department financial budget criteria is considered to ensure that the Partnership is effectively managing general and administrative costs in a prudent manner.
The Partnership's internal financial budgets are generally developed for each business segment, and then aggregated with appropriate corporate level adjustments, to reflect an overall performance objective that is reasonable in light of market conditions and opportunities based on a high level of effort and dedication across all segments of the Partnership's business. The evaluation of the Partnership's performance versus its internal financial budget is based on the Partnership's Earnings Target for a calendar year. In general, the Compensation Committee believes that Partnership performance at or above the internal Earnings Target budget and at or below internal department financial budgets would support an eligible bonus pool for our NEOs ranging from 100 to 125 percent of their respective annual base earnings (which amount reflects the actual base salary earned during the calendar year to reflect periods before and after any base salary adjustment) for Ms. Shea-Ballay and Messrs. Lauterbach and Chalson and from 105 to 130 percent of his annual base earnings for Mr. Gvazdauskas. The short-term annual cash bonus pool target for Mr.

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Hennigan was set by the Compensation Committee for 2016 at 140 percent of his annual base earnings. These target ranges are the same ranges that were applicable to the 2015 ASIP awards.
In February 2017, in respect of 2016 performance under the ASIP, the Compensation Committee approved the following cash bonuses:
Name
 
2016 Cash Bonus Award
 
Cash Bonus as percent of 2016 Base Earnings
Mr. Hennigan
 
$830,092
 
132
%
Mr. Gvazdauskas
 
$306,000
 
99
%
Mr. Chalson
 
$266,000
 
94
%
Mr. Lauterbach
 
$312,000
 
94
%
Ms. Shea-Ballay
 
$318,000
 
94
%
In approving the 2016 bonuses of the NEOs, the Compensation Committee took into account the achievement by the Partnership of all of its targeted performance objectives for 2016 and the individual performances of these individuals with respect to (i) promoting the Partnership's financial, strategic and operating objectives, (ii) the Partnership's success in exceeding its internal financial budget, (iii) the development of new projects that are expected to result in increased cash flows from operations in future years, (iv) the completion of mergers, acquisitions or similar transactions that are expected to be accretive to the Partnership and increase distributable cash flow, and (v) the overall management of the Partnership's business. The cash bonuses awarded to the NEOs in respect of 2016 performance are consistent with the Partnerships' applicable bonus pool targets for each NEO.
•
Long-Term Incentive Awards (Equity Awards):
•
Why the LTIP was adopted: Long-term incentive awards for executive officers are granted under the LTIP in order to promote achievement of our long-term strategic business objectives. The LTIP was designed to align the economic interests of executive officers, key employees and directors with those of our unitholders and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive awards are based upon the common units representing limited partnership interests in us, although they may be payable in common units or in cash. The Compensation Committee administers the LTIP and, in its discretion, may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the common units are listed at that time. Changes to any outstanding grant that would materially impair the rights of a participant cannot be made without the consent of the affected participant.
On December 1, 2015, our limited partners approved the amended and restated LTIP at a special meeting called for that purpose. In addition to certain other non-material administrative changes, the amended and restated LTIP (i) authorized an additional 10 million common units to be available for delivery with respect to awards under the plan, (ii) added additional types of awards that can be granted under the plan, such as phantom unit awards, unit appreciation rights, unrestricted unit awards and other unit-based awards, (iii) added a prohibition on repricing of unit options and unit appreciation rights without the approval of the unitholders, and (iv) provided for termination of the plan at the earliest of the date it is terminated by the Board, the date no more units remain available for grants and December 1, 2025. The remainder of this CD&A describes the LTIP as amended and restated by the unitholders.
•
The elements of compensation under the LTIP: The LTIP provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights, unit awards or other unit-based awards. No types of awards other than restricted units have been granted since the inception of the LTIP.
Each restricted unit entitles the grantee to receive a common unit upon vesting or, in the discretion of the Compensation Committee, an amount of cash equivalent to the then-current value of a common unit at the time of vesting. From time to time, the Compensation Committee may make grants under the plan to employees and/or directors containing such terms as the Compensation Committee shall determine under the LTIP. The Compensation Committee determines the conditions upon which the restricted units granted may become vested or forfeited, and whether the restricted units will have distribution equivalent rights ("DERs") entitling the grantee to receive an amount in cash equal to cash distributions made by us with respect to a like number of our common units during the restricted period.
In December of 2016, consistent with the compensation methodology of ETP, all of the restricted units granted, including to the NEOs, provided for vesting of 60 percent at the end of the third year and vesting of the

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remaining 40 percent at the end of the fifth year, subject to continued employment of the NEO through each specified vesting date. These restricted unit awards entitle the grantee of the unit awards to receive, with respect to each Partnership common unit subject to such restricted unit award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by us to our unitholders. In approving the grant of such unit awards, the Compensation Committee took into account the same factors as discussed above under the caption "Annual Bonuses," the long-term objective of retaining such individuals as key drivers of the Partnership's future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting.
In December 2016, for their performance relative to the 2016 calendar year, the Compensation Committee approved grants of restricted units to Messrs. Hennigan and Gvazdauskas, Ms. Shea-Ballay and Messrs. Lauterbach and Chalson of 133,508 restricted units, 29,668 restricted units, 25,305 restricted units, 15,707 restricted units and 19,935 restricted units, respectively.
The issuance of restricted units pursuant to the LTIP is intended to serve as a means of incentive compensation; therefore, no consideration will be payable by the plan participants upon issuance or vesting of the restricted units.
Except as otherwise provided in an award agreement, the restricted units under the LTIP generally require the continued employment of the recipient during the vesting period. The NEOs' December 2016 award agreements include provisions for acceleration of their respective unvested restricted unit awards upon a change of control (as defined in the LTIP), death or disability. Such award agreements also provide that a NEO with at least ten years of service with the general partner, who leaves the general partner voluntarily due to retirement, is eligible for accelerated vesting of 40 percent of his or her award for a NEO age 65 to 68 or 50 percent of his or her award for a NEO over age 68.
•
Accounting and Tax Considerations: We account for the equity compensation expense of our general partner's employees, including the NEOs, in accordance with GAAP, which requires us to estimate and record an expense for each equity award over the vesting period of the award. The expense for restricted units settled in common units is recognized ratably over the vesting period. For cash compensation, the accounting rules require us to record it as an expense at the time the obligation is accrued. Because we are a partnership, and our general partner is a limited liability company, Internal Revenue Code ("Code") Section 162(m) does not apply to the compensation paid to our NEOs and, accordingly, the Compensation Committee did not consider its impact in determining compensation levels for 2016.
•
Equity Grant Practices: Equity awards to employees are approved at meetings of our general partner's Compensation Committee. In limited situations, however, such awards may be approved by unanimous written consent of the Compensation Committee. The grant date of an equity award is the date of the Compensation Committee meeting at which such equity award is approved. The Compensation Committee may, in its discretion, refrain from approving grants of equity awards to employees if the meeting at which such approval is to be considered occurs during a period in which management is in possession of material non-public information, in which case, approval of such equity awards may be deferred to the next Compensation Committee meeting. No grant approvals were deferred to a later Compensation Committee meeting in 2016.
•
Unit Ownership Guidelines: Our general partner has established guidelines for the ownership of our common units, applicable to certain executives of the general partner with respect to common units representing limited partnership interests in the Partnership. The applicable unit ownership guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under the current guidelines, the President and Chief Executive Officer is expected to own common units having a minimum value of five times his base salary, the Chief Financial Officer and Treasurer is expected to own common units having a minimum value of four times his base salary, and each of the remaining NEOs are expected to own common units having a minimum value of three times their respective base salaries. Our general partner and the Compensation Committee believe that the ownership of our common units, as reflected in these guidelines, is an important means of tying the financial risks and rewards for our executives to our total unitholder return and better aligning the interests of such executives with those of our unitholders. Any executive subject to the guidelines who has not yet met his or her respective ownership guideline must accumulate our common units until such guideline is met. Except for sales of common units in settlement of tax obligations relating to the receipt and payment of LTIP awards, such persons are prohibited from disposing of any of our common units until the applicable ownership guideline has been attained. However, those individuals who have met or exceeded their applicable ownership guideline may dispose of our common units in a manner consistent with applicable law and our policies, but only to the extent that such individual's remaining ownership of common units would continue to exceed the applicable ownership guideline.

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•
Insider Trading (Including Hedging) Policy: The employees of our general partner are subject to the Sunoco Partners LLC Insider Trading Policy which, among other things, prohibits such employees from entering into short sales, or purchasing, selling, or exercising any puts, calls, or similar derivative security instruments pertaining to our common units, all of which could incentivize an employee towards engaging in overly risky behavior for short-term gains. This prohibition does not extend to unit options that may be issued in accordance with the terms of the LTIP.
•
Other Plans: During 2016, employees of our general partner, including the NEOs, participated in the following benefit plans offered by ETP or its affiliates, including certain of Sunoco, Inc.'s plans, in which our general partner was a participating employer prior to the merger transaction with ETP (the "Merger") and continues to participate. Sunoco, Inc., a Pennsylvania corporation ("Sunoco"), owned our general partner prior to the Merger. In connection with the Merger, Sunoco became a wholly-owned subsidiary of ETP and its affiliates and transferred its membership interests in our general partner to ETP.
•
The Sunoco, Inc. Retirement Plan (the "SCIRP") was a qualified defined benefit plan, under which benefits were subject to Code limits for pay and amount. On October 31, 2014, Sunoco terminated the SCIRP. Following the SCIRP's receipt in November 2015 of a favorable Determination Letter from the Internal Revenue Service ("IRS") for such standard termination, benefit distributions were made in December 2015 to those participants electing to commence receipt of benefits from the SCIRP, which included each of the NEOs other than Mr. Lauterbach. On December 22, 2015, Sunoco transferred all of the SCIRP's future benefit obligations to an insurance company through the purchase of a group annuity contract ("GAC"). The GAC obligates the insurance company to provide all future benefits to participants, in accordance with the existing SCIRP provisions in existence on December 22, 2015. The single lump sum value of Mr. Lauterbach's SCIRP benefit that was transferred to the insurance company, valued on March 1, 2016, was $249,397. Effective upon the purchase of the GAC, the insurance company is solely responsible for providing Mr. Lauterbach's benefit, including all interest earned. The provisions of the SCIRP that are still applicable to Mr. Lauterbach are described below under "Pension Benefits."
•
The Sunoco, Inc. Pension Restoration Plan (the "Pension Restoration Plan") is a nonqualified plan that provides retirement benefits that otherwise would have been provided under the SCIRP, except for the Code limits. Effective June 30, 2010, Sunoco froze benefits, including accrued and vested benefits, payable under this plan for all salaried employees of our general partner who participate in this plan, including the NEOs. Benefits from the Pension Restoration Plan are payable upon the eligible NEO's separation of service.
•
The Energy Transfer Partners GP, L.P. 401(k) Plan (the "ETP 401(k) Plan") is a defined contribution 401(k) plan, which covers substantially all of our general partner's employees, including the NEOs. Employees may elect to defer up to 75 percent of their eligible compensation before applicable taxes, as limited under the Code. For 2016, a participant was eligible to make elective deferrals up to $18,000. The Partnership provides a matching contribution equal to 100 percent on the first five percent of each participant's elective deferrals. Participants age 50 or over at any time in 2016 could elect to make a catch-up contribution of up to $6,000. Catch-up contributions are not eligible for a matching contribution from the Partnership. The amounts deferred by the participant to the ETP 401(k) Plan account are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
•
The ETP Deferred Compensation Plan (the "ETP DC Plan") is a nonqualified deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ETP DC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50 percent of their annual base salary, 50 percent of their DER payments, and/or 50 percent of their annual bonus under the ASIP during the following year. Pursuant to the ETP DC Plan, the Partnership may make annual discretionary matching contributions to participants' accounts; however, the Partnership has not made any discretionary contributions to participants' accounts and currently has no plans to make any discretionary contributions to participants' accounts. All amounts credited under the ETP DC Plan, other than discretionary credits, are immediately 100 percent vested. Participant accounts are credited with deemed earnings (or losses) based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their ETP DC Plan account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a

123


change of control, as defined in the ETP DC Plan, all ETP DC Plan accounts are immediately vested in full, and participants may elect to have their accounts distributed in one lump sum payment or to retain their originally elected payment schedules.
•
The ETP Deferred Compensation Plan for Former Sunoco Executives is a nonqualified deferred compensation plan established by ETP in connection with the October 2012 merger ("2012 Merger"). Pursuant to his offer letter agreement with ETP effective as of October 5, 2012, in connection with the 2012 Merger (the "Offer Letter"), Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under both the Sunoco, Inc. Executive Retirement Plan ("SERP"), a nonqualified plan that provided supplemental pension benefits over and above the benefits under the SCIRP and the Pension Restoration Plan, and the Pension Restoration Plan, in return for which, the present value ($2,789,413) of such deferred compensation benefits was credited to Mr. Hennigan's account under this plan. Mr. Hennigan is our only executive officer eligible to participate in this plan. Mr. Hennigan's account is 100 percent vested and will be distributed in one lump sum payment upon his retirement, termination of employment or other designated distribution event, including a change of control, as defined in the plan. His account is credited with deemed earnings (or losses) based on hypothetical investment fund choices made by him among available funds.
•
Other Benefits: Employees of our general partner, including NEOs, participate in the Energy Transfer Partners GP, L.P. Health and Welfare Program for Active Employees (the "Midstream Plan"). The Midstream Plan offers a variety of other benefits arrangements, including medical, dental, vision, life insurance, disability insurance, holidays and vacation, offered to similarly situated employees. These benefits arrangements, which are the same for all midstream employees of the ETE family of partnerships, are provided on an enterprise-wide basis. NEOs receive the same benefits and are responsible to pay the same premium, deductible and out-of-pocket maximums as other employees.
•
Severance Benefits: An employee, including an NEO, is an employee at will. This means that our general partner may terminate an employee's employment at any time, with or without notice, and with or without cause or reason. Our NEOs do not have employment agreements or any other agreements, other than certain LTIP acceleration events described below, that call for payments on termination or severance benefits upon separation from employment or in the event of a Change of Control of the general partner. Upon certain terminations of employment, certain benefits may be paid or provided to our NEOs. Our general partner has adopted the Energy Transfer Partners GP, L.P. Severance Plan (the "Severance Plan"), which provides for payment of severance benefits in the event of certain qualifying terminations (defined below) to all salaried employees on a nondiscriminatory basis. In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service with the general partner up to a maximum of fifty-two weeks (or one year) of annual base salary, with a minimum of four weeks of annual base salary. The Severance Plan also provides up to three months of continued, subsidized group health insurance coverage under the Consolidated Omnibus Budget Reconciliation Act ("COBRA"). The Severance Plan provides that the Partnership may determine to pay benefits, in addition to those provided under the Severance Plan, based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan defines a qualifying termination as an involuntary termination that occurs in connection with a reduction-in-force, reorganization, restructuring, position elimination or any other termination designated by the plan administrator as a qualifying termination, although a qualifying termination may not be a termination for cause, retirement, death, disability or a voluntary resignation for any reason.


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SUMMARY COMPENSATION TABLE
The Summary Compensation Table reflects the total compensation earned by each NEO in each of 2016, 2015 and 2014 (or such shorter period of time during which such individual served as an executive officer of the general partner):
Name and
Principal
Position
 
Year
 
Salary
($)
 
Bonus (1)
($)
 
Unit Awards (2)
($)
 
Change in Pension Value and Nonqualified Deferred Compensation Earnings (3)
($)
 
All Other
Compensation (4)
($)
 
Total
($)
M. J. Hennigan
 
2016
 
630,769

 
830,092

 
3,088,040

 
—

 
789,008

 
5,337,909

President and Chief
 
2015
 
611,537

 
856,152

 
3,009,815

 
—

 
1,237,494

 
5,714,998

Executive Officer
 
2014
 
600,000

 
810,000

 
3,941,118

 
263,923

 
813,504

 
6,428,545

P. Gvazdauskas (5)
 
2016
 
310,384

 
306,000

 
686,221

 
—

 
103,651

 
1,406,256

Chief Financial Officer and
 
2015
 
261,223

 
274,283

 
601,963

 
—

 
80,363

 
1,217,832

Treasurer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
K. Shea-Ballay
 
2016
 
338,092

 
318,000

 
585,305

 
882

 
111,776

 
1,354,055

Senior Vice President,
 
2015
 
325,713

 
325,713

 
537,745

 
—

 
158,608

 
1,347,779

General Counsel & Secretary
 
2014
 
313,875

 
300,000

 
494,660

 
13,785

 
139,988

 
1,262,308

K. Lauterbach
 
2016
 
332,411

 
312,000

 
363,303

 
10,452

 
99,317

 
1,117,483

Senior Vice President,
 
2015
 
325,044

 
325,044

 
361,178

 
—

 
375,778

 
1,387,044

Lease Acquisition and Marketing
 
2014
 
317,419

 
300,000

 
484,752

 
23,462

 
130,043

 
1,255,676

D. Chalson
 
2016
 
282,550

 
266,000

 
461,097

 
522

 
102,135

 
1,112,304

Senior Vice President,
 
2015
 
276,290

 
276,290

 
401,317

 
—

 
97,247

 
1,051,144

Operations
 
2014
 
269,806

 
300,000

 
469,937

 
49,288

 
84,948

 
1,173,979

 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
The amounts shown in this column reflect annual bonuses payable under the ASIP for performance during 2016, 2015 and 2014, as applicable, which are payable on or before March 15th of the year immediately following the year to which the plan related.
(2) 
The amounts shown in this column reflect the aggregate grant date fair value of restricted unit awards under the LTIP, calculated in accordance with FASB ASC Topic 718, disregarding the estimate of forfeitures. See Note 14 to our consolidated financial statements for fiscal 2016 for additional detail regarding assumptions underlying the value of these equity awards. The amounts shown in this column generally reflect the grants of time-based restricted units approved by the Compensation Committee at its regularly scheduled meetings in December. However, in January 2014, the Compensation Committee approved an additional grant of restricted units to Mr. Hennigan for his performance during 2013.
(3) 
The amounts shown in this column reflect the change in present value for all defined benefit pension plans and supplemental executive retirement plans in which the NEOs participated. The applicable disclosure rules require the change in pension value be shown as zero if the actual calculation of the change in pension value is less than zero (i.e., a decrease).
During 2015, the decrease in SCIRP pension value for Messrs. Hennigan, Gvazdauskas and Lauterbach was $49,762, $1,955 and $3,339, respectively. The decrease in SCIRP pension value for Ms. Shea-Ballay was $2,100, which when added to her increase in Pension Restoration Plan pension value of $666 resulted in a total decrease in pension value of $1,434 for 2015. The decrease in SCIRP pension value for Mr. Chalson was $8,576, which when added to his increase in Pension Restoration Plan pension value of $492 resulted in a total decrease in pension value of $8,084 for 2015.
The NEOs did not have any above-market or preferential payments on deferred compensation during 2016, 2015 or 2014. During 2015, Mr. Hennigan had a loss of $139,657 under the ETP Deferred Compensation Plan for Former Sunoco Executives, and Mr. Chalson had a loss $31,788 under the ETP DC Plan.







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(4) 
The table below shows the components of this column for 2016:
Name
 
Year
 
Company Contribution
Under Defined Contribution Plan (a)
($)
 
Perquisites
>$10,000
($)
 
Restricted Unit Distribution
Rights Payments (b)
($)
 
Total
($)
M. J. Hennigan
 
2016
 
13,250

 
—

 
775,758

 
789,008

P. Gvazdauskas
 
2016
 
13,250

 
—

 
90,401

 
103,651

K. Shea-Ballay
 
2016
 
11,406

 
—

 
100,370

 
111,776

K. Lauterbach
 
2016
 
12,902

 
—

 
86,415

 
99,317

D. Chalson
 
2016
 
13,250

 
—

 
88,885

 
102,135

 
(a) 
During 2016, our general partner was a participating employer in the ETP 401(k) Plan, which provides a matching contribution equal to 100 percent on the first five percent of each participant's elective deferrals.
(b) 
The amounts shown in this column reflect the cash payments made to each NEO during 2016, which were equal to each cash distribution per common unit made by us on our common units during 2016 with respect to each common unit subject to a restricted unit held by such NEO that has not either vested or been forfeited. Pursuant to the terms of the awards, these cash amounts are paid quarterly.
(5) 
Compensation information for only fiscal year 2016 and 2015 is provided for Mr. Gvazdauskas because he was not a NEO in fiscal year 2014.

126


GRANTS OF PLAN-BASED AWARDS
The following table sets forth the grants of plan-based awards to NEOs in 2016:
Name
 
Grant Date (1)
 
All Other Unit Awards:
Number of Units (2)
(#)
 
Grant Date Fair Value of Unit Awards 
($)
M. J. Hennigan
 
12/12/2016
 
133,508

 
3,088,040

President and Chief Executive Officer
 
 
 
 
 
 
P. Gvazdauskas
 
12/12/2016
 
29,668

 
686,221

Chief Financial Officer and Treasurer
 
 
 
 
 
 
K. Shea-Ballay
 
12/12/2016
 
25,305

 
585,305

Senior Vice President, General Counsel & Secretary
 
 
 
 
 
 
K. Lauterbach
 
12/12/2016
 
15,707

 
363,303

Senior Vice President, Lease Acquisition and Marketing
 
 
 
 
 
 
D. Chalson
 
12/12/2016
 
19,935

 
461,097

Senior Vice President, Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
The restricted unit awards vest 60 percent in December 2019 and the remaining 40 percent in December 2021.
(2) 
Reflects the grant date fair value of restricted unit awards granted under the LTIP during fiscal 2016, computed in accordance with FASB ASC Topic 718. See Note 14 to our consolidated financial statements for fiscal 2016 for additional detail regarding assumptions underlying the value of these equity awards.

Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above can be found in the CD&A that precedes these tables.



127


OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table provides information concerning the unvested and outstanding equity awards to each current NEO as of December 31, 2016:
Name
 
 
 
Unit Awards
Grant Date (1)
 
Number of Units That Have Not Vested
(#)
 
Market Value of Units That Have Not Vested (2)
($)
M. J. Hennigan
 
12/12/2016
 
133,508

 
3,206,862

President and Chief Executive Officer
 
12/4/2015
 
116,750

 
2,804,335

 
 
12/5/2014
 
74,043

 
1,778,513

 
 
1/29/2014
 
4,000

 
96,080

 
 
12/5/2013
 
34,960

 
839,739

 
 
1/24/2013
 
16,000

 
384,320

 
 
12/5/2012
 
36,000

 
864,720

 
 
 
 
 
 
 
P. Gvazdauskas
 
12/12/2016
 
29,668

 
712,625

Chief Financial Officer and Treasurer
 
12/4/2015
 
23,350

 
560,867

 
 
12/5/2014
 
9,153

 
219,855

 
 
12/5/2013
 
3,680

 
88,394

 
 
1/24/2013
 
2,000

 
48,040

 
 
 
 
 
 
 
K. Shea-Ballay
 
12/12/2016
 
23,305

 
607,826

Senior Vice President, General Counsel & Secretary
 
12/4/2015
 
20,859

 
501,033

 
 
12/5/2014
 
10,284

 
247,022

 
 
12/5/2013
 
5,600

 
134,512

 
 
1/24/2013
 
2,800

 
67,256

 
 
 
 
 
 
 
K. Lauterbach
 
12/12/2016
 
15,707

 
377,282

Senior Vice President, Lease Acquisition and Marketing
 
12/4/2015
 
14,010

 
336,520

 
 
12/5/2014
 
10,078

 
242,074

 
 
12/5/2013
 
5,600

 
134,512

 
 
1/24/2013
 
2,800

 
67,256

 
 
 
 
 
 
 
D. Chalson
 
12/12/2016
 
19,935

 
478,839

Senior Vice President, Operations
 
12/4/2015
 
15,567

 
373,919

 
 
12/5/2014
 
9,770

 
234,675

 
 
12/5/2013
 
5,600

 
134,512

 
 
1/24/2013
 
2,800

 
67,256

 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
The restricted unit awards vest as follows:
•
ratably in December of each year through 2017 for Mr. Hennigan's awards granted in December 2012;
•
ratably in December of each year through 2017 for awards granted in January 2013;
•
60 percent in December 2016 and the remaining 40 percent in December 2018 for awards granted in December 2013;
•
60 percent in December 2016 and the remaining 40 percent in December 2018 for Mr. Hennigan's award granted in January 2014;
•
60 percent in December 2017 and the remaining 40 percent in December 2019 for awards granted in December 2014;
•
60 percent in December 2018 and the remaining 40 percent in December 2020 for awards granted in December 2015; and
•
60 percent in December 2019 and the remaining 40 percent in December 2021 for awards granted in December 2016.
(2) 
The market value or payout value of the unearned restricted units is equal to the closing price of our common units on December 30, 2016 of $24.02 (as December 31, 2016 was not a trading day), multiplied by the number of restricted units outstanding. The amounts shown in this column do not include amounts for related DER payments that could be included in the payout. See "Potential Payments Upon Termination or Change of Control" for a discussion of the treatment of these awards under certain termination events or in the event of a change of control.

128


OPTION EXERCISES AND UNITS VESTED
The following table provides information concerning the vesting in 2016 of certain restricted units, previously awarded under the LTIP to the NEOs: 
Name
 
Unit Awards
Number of Units Acquired on Vesting (1)
(#)
 
Value Realized on Vesting (2)
($)
M. J. Hennigan
 
110,440

 
2,559,999

President and Chief Executive Officer
 
 
 
 
P. Gvazdauskas
 
7,520

 
174,314

Chief Financial Officer and Treasurer
 
 
 
 
K. Shea-Ballay
 
11,200

 
259,616

Senior Vice President, General Counsel & Secretary
 
 
 
 
K. Lauterbach
 
11,200

 
259,616

Senior Vice President, Lease Acquisition and Marketing
 
 
 
 
D. Chalson
 
11,200

 
259,616

Senior Vice President, Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
The amounts shown in this column reflect the vesting and payout, in the form of our common units, of LTIP grants during 2016.
(2) 
Value realized on vesting was determined by multiplying the number of common units to be issued upon vesting by the closing market price of our common units on the date prior to the vesting date. These amounts do not reflect the value of units withheld by our general partner to satisfy tax withholding obligations.


129


PENSION BENEFITS
Our general partner was a participating employer in Sunoco's SCIRP prior to its standard termination on October 31, 2014. All of our NEOs were eligible to participate in the SCIRP, and all NEOs other than Mr. Lauterbach received a full settlement of their SCIRP accounts during the 2015 year. Mr. Lauterbach still has an account balance within the SCIRP and the table below shows that amount. Mr. Lauterbach's vested SCIRP benefit, effective December 22, 2015, is the sole obligation of an insurance company following Sunoco's purchase of a group annuity contract for the provision of such benefits.
Certain of our NEOs (Ms. Shea-Ballay and Mr. Chalson) are participants in the Pension Restoration Plan, which was frozen on June 30, 2010. The table below also shows the annual retirement benefit payable to the covered executives under the Pension Restoration Plan, each based upon a cash balance formula.
Name
 
Plan
 
Number of
Years Credited
Service (1)
(#)
 
Present Value of
Accumulated
Benefit
Year-end 2016 (2)
($)
 
Payments
During
Last Fiscal Year (3)
($)
K. Shea-Ballay
 
Pension Restoration
 
5.19

 
13,682

 
—

Senior Vice President, General Counsel & Secretary
 
 
 
 
 
 
 
 
K. Lauterbach
 
SCIRP (Qualified)
 
12.73

 
258,138

 
—

Senior Vice President, Lease Acquisition and Marketing
 
 
 
 
 
 
 
 
D. Chalson
 
Pension Restoration
 
24.18

 
12,339

 
—

Senior Vice President, Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
Credited years of service reflect actual plan service with the general partner, including years of service credited with Sunoco prior to employment with our general partner.
(2) 
Mr. Lauterbach's accrued benefits under the SCIRP have been deferred until his next eligible benefit commencement date and have been transferred to an insurance company for management and payment at the applicable time. The present value of his benefits has been set equal to his actual cash balance account as of December 31, 2016, which is equivalent to valuing the present value with a discount rate of 4.22 percent, or the Career Pay Formula interest crediting rate, and which present value is lower than his estimate at year-end 2014.
The actuarial present values of the Pension Restoration Plan benefits for Ms. Shea-Ballay and Mr. Chalson are calculated using assumed retirement ages of 60 and 65, respectively, and were discounted to December 31, 2016 using a rate of 3.80 percent. The assumed retirement age is the earlier of the Pension Restoration Plan's stated normal retirement age (if any) and the earliest age at which retirement benefits are available without reduction for age. Because there are no benefit reductions for early commencement under Pension Restoration Plan, the later of age 60 or age next birthday (plus one year) were used for assumed retirement age. All pre-retirement decrements such as pre-retirement mortality and terminations of employment have been ignored for purposes of these calculations. Each NEO is assumed to have a 100 percent probability of reaching the assumed retirement age. Actual benefit present values will vary from these estimates depending on many factors, including an executive's actual retirement age, interest rate movements and regulatory changes.
The Sunoco, Inc. Retirement Plan
The SCIRP was a qualified defined benefit retirement plan that covered most salaried and many hourly employees, including the NEOs. The SCIRP provided for normal retirement at age 65. The plan included two benefit formulas, the Final Average Pay formula and the Career Pay formula, but Mr. Lauterbach was only eligible to receive the Career Pay formula below:
Career Pay (cash balance) formula
•
The retirement benefit is expressed as an account balance, comprised of pay credits and indexing adjustments.
•
Pay credits equal seven percent of pay for the year up to the Social Security (FICA) Wage Base ($113,700 in 2013, $117,000 in 2014, and $118,500 in 2015) plus 12 percent of pay that exceeds the Wage Base for the year.
•
Beginning November 1, 2014, in connection with the SCIRP's standard termination, the indexing adjustment was fixed at 4.22 percent annually.
An employee could retire at the Normal Retirement Age of 65, or could retire as early as age 55 with 10 years of service. All employees of our general partner, including our NEOs who were participants in the SCIRP, were 100 percent vested in their benefits. Mr. Lauterbach was eligible for early retirement under the SCIRP.

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The normal form of benefit under the SCIRP was an annuity for the life of the employee, with 50 percent of that annuity paid for the life of the employee's surviving spouse (50 percent Joint and Survivor Benefit). This 50 percent Joint and Survivor benefit was free for participants who were retired under the plan, and who benefited under the SCIRP's Final Average Pay formula. However, the participant's monthly annuity was reduced actuarially for those who benefited under the SCIRP's Career Pay formula. Other forms of payment were also offered such as a lump sum and other annuity options. Under the Final Average Pay formula, the lump sum was the actuarial equivalent of the annuity benefit, based upon current IRS-prescribed interest rates and mortality tables, while under the Career Pay formula, the lump sum was equal to the value of the employee's account.
The amounts presented in the table above show Mr. Lauterbach's benefit presented as his Career Pay formula account balance at December 31, 2016. Mr. Lauterbach's benefit has been transferred to an insurance company for management and payment at the applicable time.

Sunoco, Inc. Pension Restoration Plan
The Pension Restoration Plan is a nonqualified plan that provides retirement benefits that would have been provided under the SCIRP, but were prohibited from being paid from the SCIRP by the Code limits. Participants in the SCIRP whose annual compensation exceeded the applicable Code limits while the plan was still active were eligible to participate in the Pension Restoration Plan. The benefit paid by the Pension Restoration Plan is the total benefit accrued under the SCIRP, without regard to Code limits, less the amount of benefit that the SCIRP was permitted to provide under the Code.
All benefits under the Pension Restoration Plan are calculated using the same formulas applicable under the SCIRP. The amounts presented in the table above are actuarial present values based on accrued annual benefits, using pay and benefit service through June 30, 2010. The actual amount distributed as a lump sum will vary from the amount provided in the table depending on the actual date of termination or retirement, which will determine the actual amount of indexing credited to the account balance. Payment of benefits is made upon termination of employment, except that payment of amounts subject to Code Section 409A is delayed until six months after separation from service for any specified employee as defined under Code Section 409A. No additional benefits are being accrued after June 30, 2010 under the Pension Restoration Plan.





131


NONQUALIFIED DEFERRED COMPENSATION
ETP Deferred Compensation Plan
The following table provides the voluntary salary deferrals made by the NEOs in 2016 under the ETP DC Plan, a nonqualified deferred compensation plan that permits eligible highly compensated employees to defer a portion of their salary, bonus and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ETP DC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50 percent of their annual base salary, 50 percent of their DER payments, and/or 50 percent of their annual bonus under the ASIP during the following year. All amounts credited under the ETP DC Plan (other than discretionary credits) are immediately 100 percent vested. Participant accounts are credited with deemed earnings (or losses) based on hypothetical investment fund choices made by the participants among available funds. Mr. Chalson is the only NEO that currently participates in the ETP DC Plan.
Name
 
Executive
Contributions
in 2016
($)
 
Registrant
Contributions
in 2016
($)
 
Aggregate
Earnings in 2016 (1)
($)
 
Aggregate
Withdrawals/
Distributions
in 2016
($)
 
Aggregate
Balance at
December 31, 2016
($)
D. Chalson
 
116,510

 
—

 
106,971

 
—

 
519,978

Senior Vice President, Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
These amounts reflect the net gains (losses) attributable to the investment funds in which Mr. Chalson is deemed to have chosen to invest his contributions under the ETP DC Plan.




132


ETP Deferred Compensation Plan for Former Sunoco Executives
The following table includes deferred compensation provided to the NEOs in 2016 under the ETP Deferred Compensation Plan for Former Sunoco Executives, a nonqualified deferred compensation plan established by ETP in connection with the Merger. Pursuant to his Offer Letter, Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under both the SERP and the Pension Restoration Plan, in return for which, the present value ($2,789,413) of such deferred compensation benefits was credited to Mr. Hennigan's account under this plan. Mr. Hennigan is our only executive officer eligible to participate in this plan. Mr. Hennigan's account is credited with deemed earnings (or losses) based on hypothetical investment fund choices made by him among available funds.
Name
 
Executive
Contributions
in 2016
($)
 
Registrant
Contributions
in 2016
($)
 
Aggregate
Earnings in 2016 (1)
($)
 
Aggregate
Withdrawals/
Distributions in 2016
($)
 
Aggregate
Balance at
December 31, 2016
($)
M. J. Hennigan
 
—

 
—

 
360,066

 
—

 
3,682,582

President and Chief Executive Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
These amounts reflect the net gains (losses) attributable to the investment funds in which Mr. Hennigan is deemed to have chosen to invest his contributions under the ETP Deferred Compensation Plan for Former Sunoco Executives.


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OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS
Certain plans, as described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, retirement, or a change of control of our general partner. The amounts included below reflect the estimated potential compensation and benefits for the NEOs under various scenarios involving a termination of employment. These amounts are estimates of the amounts that would be paid to the NEOs and the actual amounts paid can only be determined at the time of the NEO's termination of employment. These estimates are based on the assumptions that the triggering event occurred on December 31, 2016 and the transaction price per Partnership unit is $24.02, which was the closing price of our common units on December 30, 2016 (as December 31, 2016 was not a trading day).
•
Retirement:
•
SCIRP/Pension Restoration Plan: The benefits payable to the NEOs upon retirement are described above in the section entitled "Pension Benefits."
•
LTIP: Outstanding restricted units would be forfeited unless specified in the applicable award agreement. The NEOs' December 2016 and 2015 award agreements provide that a NEO with at least ten years of service with the general partner, who leaves the general partner voluntarily due to retirement, is eligible for accelerated vesting of 40 percent of his or her award for a NEO age 65 to 68 or 50 percent of his or her award for a NEO over age 68. Under the assumptions described above, none of the restricted units granted in December 2016 and 2015 would vest upon a NEO's retirement because none of the NEOs met the age criteria for vesting at such time.
•
Voluntary Termination: Mr. Lauterbach elected to defer his benefits under the SCIRP and would be eligible for payment of his SCIRP benefit from the selected insurance company upon voluntary termination. NEOs participating in the Pension Restoration Plan (Ms. Shea-Ballay and Mr. Chalson) would be eligible to receive their benefit as a lump sum six months following their date of termination.
•
Involuntary Termination-For Cause: Benefits accrued under the SCIRP and Pension Restoration Plan would be paid according to the terms of those plans applicable to terminated or retirement eligible employees, as described in the Voluntary Termination section above.
•
Involuntary Termination-Not for Cause:
•
SCIRP/Pension Restoration Plan: Benefits accrued under the SCIRP and Pension Restoration Plan would be paid according to the terms of those plans applicable to terminated or retirement eligible employees, as described in the Voluntary Termination section above.
•
LTIP: Outstanding restricted units would be forfeited unless specified in the applicable award agreement. Mr. Hennigan's award agreement for restricted units granted in December 2014 and his October 5, 2012 Offer Letter provide for vesting immediately upon involuntary not-for-cause termination. Under the assumptions described above, Mr. Hennigan's restricted units granted in December 2014 and December 2012 would vest at a total value of $3,143,222 upon his involuntary not-for-cause termination, which value includes DER payments due to accelerated vesting of unit ownership.
•
Severance Plan: The NEOs would be eligible for severance benefits under the Severance Plan. At a maximum, the NEOs could receive one year of salary as a cash severance benefit, and could receive up to three months of COBRA continuation coverage.
•
Involuntary Termination-Change of Control:
•
SCIRP/Pension Restoration Plan: Benefits accrued under the SCIRP and Pension Restoration Plan would be paid according to the terms of those plans applicable to terminated or retirement eligible employees, as described in the Voluntary Termination section above.
•
LTIP: Under the version of the LTIP prior to the amended and restated LTIP adopted on December 1, 2015 (the "Original LTIP"), unless specified otherwise in the applicable award agreement, if a change of control occurs, there is a "double trigger" mechanism, requiring both a change of control and a qualifying termination of employment (as defined in the plan) following such change of control, to trigger the payment of outstanding restricted units and accompanying DER payments. All restricted units granted prior to December 1, 2015 remain subject to the terms and conditions of the Original LTIP. Under the amended and restated LTIP, awards may also become vested upon a change of control at the discretion of the Compensation Committee, or if otherwise specified in the applicable award agreement. The NEOs' December 2016 and 2015 award agreements provide for vesting immediately upon a change of control. Under the assumptions described above, and assuming the occurrence of the double trigger for the restricted units granted prior to

134


December 1, 2015, all outstanding restricted units held by the NEOs would vest for Messrs. Hennigan, Gvazdauskas, Lauterbach and Chalson and Ms. Shea-Ballay at a total value of $11,005,622, $1,741,194, $1,268,862, $1,402,361 and $1,683,175, respectively, upon a change of control, each of which values includes DER payments due to accelerated vesting of unit ownership.
•
ETP DC Plan and ETP Deferred Compensation Plan for Former Sunoco Executives: As discussed in our CD&A above, all amounts under the ETP DC Plan and the ETP Deferred Compensation Plan for Former Sunoco Executives (other than discretionary credits) are 100 percent vested. Upon a change in control (as defined in the ETP DC Plan and the ETP Deferred Compensation Plan for Former Sunoco Executives), distributions from the ETP DC Plan and/or the ETP Deferred Compensation Plan for Former Sunoco Executives would be made in accordance with the normal distribution provisions. A change in control is generally defined in the ETP DC Plan and the ETP Deferred Compensation Plan for Former Sunoco Executives as any change in control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
•
Severance Plan: The Severance Plan would not provide any enhanced benefits to the NEOs upon an involuntary termination that is in connection with a change in control event. If an NEO is terminated by us without cause in connection with a change in control benefit, the NEO would not receive benefits in excess of the amounts set forth above with respect to an involuntary termination without cause.
•
Death:
•
SCIRP/Pension Restoration Plan: Due to the SCIRP's standard termination, Mr. Lauterbach's spouse, beneficiary(ies) or estate would receive from the selected insurance company 100 percent of his benefit accrued under the Career Pay formula. The spouse, beneficiary(ies) or estate of Ms. Shea-Ballay and Mr. Chalson, as applicable, would be eligible to receive 100 percent of his or her benefit payable from the Pension Restoration Plan.
•
LTIP: Outstanding restricted units would be forfeited unless specified in the applicable award agreement. The NEOs' December 2016, December 2015 and December 2014 award agreements, as well as Mr. Hennigan's October 5, 2012 Offer Letter, provide for vesting immediately upon death. Under the assumptions described above, Mr. Hennigan's restricted units granted in December 2016, December 2015, December 2014 and December 2012 would vest at a total value of $9,385,350, and Messrs. Gvazdauskas', Lauterbach's and Chalson's and Ms. Shea-Ballay's restricted units granted in December 2016, December 2015 and December 2014 would vest at a total value of $1,573,336, $1,020,806, $1,154,306 and $1,435,119, respectively, upon his or her death, each of which values includes DER payments due to accelerated vesting of unit ownership.
•
Life Insurance: In the event of death, the NEOs participate in the life insurance plans offered to all of our employees (i.e., basic life insurance benefits equal to one and one-half times the NEO's annual base salary, up to a maximum of $750,000 plus any supplemental life insurance benefit (one times to six times base salary, to a maximum of $2,000,000) elected and paid for by the NEO).
•
Termination Due to Disability:
•
SCIRP/Pension Restoration Plan: Benefits accrued under the SCIRP and Pension Restoration Plan would be paid according to the terms of those plans applicable to terminated or retirement eligible employees, as described in the Voluntary Termination section above.
•
LTIP: Under the Original LTIP, all unvested restricted units will be paid out as awarded in the event of permanent disability. All restricted units granted prior to December 1, 2015 remain subject to the terms and conditions of the Original LTIP. Under the amended and restated LTIP, outstanding restricted units would be forfeited unless specified in the applicable award agreement. The NEOs' December 2016 and December 2015 award agreements provide for vesting immediately upon termination due to disability. Under the assumptions described above, all outstanding restricted units held by the NEOs would vest for Messrs. Hennigan, Gvazdauskas, Lauterbach and Chalson and Ms. Shea-Ballay at a total value of $11,005,622, $1,741,194, $1,268,862, $1,402,361 and $1,683,175, respectively, upon his or her termination due to disability, each of which values includes DER payments due to accelerated vesting of unit ownership.
•
Long Term Disability: The Executive Long Term Disability Plan ("ELTD") provides salary replacement benefits to executives, who become eligible before age 60, at the Senior Vice President level or higher. To participate, an executive must make an affirmative election during the biannual open enrollment. The ELTD pays benefits if the participant is deemed to be disabled, as defined by the ELTD, by the general partner's disability plan administrator. The ELTD provides salary replacement benefits (up to $7,500 per month) that are in addition to our long-term disability plan benefit that is available to all salaried employees on a nondiscriminatory basis (which benefits are up to 60 percent of total monthly compensation or $10,000 per

135


month, whichever is less, including Social Security). While the cost of the ELTD is paid entirely by the Partnership, the executive has the option under the ELTD to increase his or her coverage by an additional $2,500 per month. This additional benefit is available to participants who pay the full cost of the supplemental benefit. In 2016, of the NEOs, only Mr. Chalson was a participant in Partnership-paid benefit level of the ELTD. No NEO was a participant in the employee-paid benefit level. These benefits are fully insured, and there is no cost to the Partnership upon disability. The cost to the Partnership is the premium payments made on the executive's behalf.


136


DIRECTOR COMPENSATION
The Board believes that the compensation program for independent directors should be designed to attract experienced and highly qualified individuals; provide appropriate compensation for their commitment and contributions to us and our unitholders; and align the interests of the independent directors and unitholders. The Board may engage a third-party compensation consultant to benchmark director compensation against other pipeline companies, and general industry, and to provide advice regarding "best practices" and trends in director compensation. Independent directors are compensated partly in cash and partly in restricted units representing limited partnership interests in us. Currently, except as described below with respect to grants of restricted units under the LTIP to Messrs. McCrea and Mason, directors who are also employees of our general partner or its affiliates receive no additional compensation for service on the Board or any committees of the Board. As such, those officers, except for Messrs. McCrea and Mason as set forth below, are not included in the narrative or tabular disclosures below.
Each independent director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board or committees, including room, meals and transportation to and from the meetings. When traveling on Partnership business, a director occasionally may be accompanied by a spouse. Directors also may be reimbursed for attendance at qualified third-party director education programs.
Each director will be indemnified fully by us for actions associated with being a member of our general partner's Board, to the extent permitted under applicable state law.
Our program of compensation for non-employee directors (which has remained consistent since approval in 2013) consists of an annual cash retainer and equity award for all directors, which were $50,000 in cash (paid quarterly) and restricted units under the LTIP, having a fair market value equal to approximately $100,000 on the date of grant, respectively, for each director in 2016. In addition, the director compensation program includes:
•
annual retainers for the chairs of the Audit Committee and Compensation Committee, which were $15,000 and $7,500, respectively, in cash (paid quarterly) for 2016;
•
annual retainers for the members of the Audit and Compensation Committees, which were $10,000 and $5,000, respectively, in cash (paid quarterly) for 2016;
•
per meeting fees for the members of the Audit Committee and Compensation Committee, which were $1,200 and $1,200, respectively, in cash per meeting for 2016; and
•
an initial grant of 2,500 restricted common units upon a director first being elected or appointed to the Board.
In January 2016, each non-employee director received 3,900 restricted units under the LTIP, having a fair market value of approximately $100,000 on the date of grant, representing such directors' annual equity award for 2016. In addition, in January 2017, each non-employee director received 4,170 restricted units under the LTIP, having a fair market value of approximately $100,000 on the date of grant, representing such directors' annual equity award for 2017. All of the restricted units described in this paragraph vest over a five-year period, with 60 percent vesting at the end of the third year and the remaining 40 percent vesting at the end of the fifth year, subject to each director's continued service through each specified vesting date.
During 2016, Mr. McCrea, the Chairman of the Board of Directors and Group Chief Operating Officer and Chief Commercial Officer of ETE's general partner, and Mr. Mason, our director and the Executive Vice President and General Counsel of ETE's general partner, were entitled to receive grants of restricted units pursuant to the LTIP in recognition of their commitment and contributions to us and our unitholders. In December 2016, the Compensation Committee approved grants of restricted units to Messrs. McCrea and Mason of 105,738 restricted units and 25,211 restricted units, respectively. These units vest, based on continued service as a director, at a rate of 60 percent after the third year of continuous service and the remaining 40 percent after the fifth year of continuous service.
All restricted units granted to the directors entitle their holders to receive, with respect to each common unit subject to such restricted unit that has not either vested or been forfeited, a cash payment equal to each cash distribution per common unit made by us on our common units promptly following each such distribution by us to our unitholders.







137


The following table reflects the compensation paid to each of the non-employee directors of our general partner (and to Messrs. McCrea and Mason, as described above) in 2016. Mr. Hennigan's compensation received in his capacity as an employee is reported above in the Summary Compensation Table.
Name
 
Fees Earned
or Paid in
Cash (1)
($)
 
Unit
Awards (2)
($)
 
All Other
Compensation (3)
($)
 
Total
($)
Steven R. Anderson
 
74,600

 
100,893

 
24,179

 
199,672

Independent Director, Chair of Conflicts Committee and Member of Audit and Compensation Committee
 
 
 
 
 
 
 
 
Scott A. Angelle
 
77,100

 
100,893

 
24,179

 
202,172

Independent Director, Chair of Compensation Committee and Member of Audit and Conflicts Committees
 
 
 
 
 
 
 
 
Basil Leon Bray
 
79,600

 
100,893

 
24,179

 
204,672

Independent Director, Chair of Audit Committee and Member of Compensation and Conflicts Committees
 
 
 
 
 
 
 
 
James R. ("Rick") Perry (4)
 
59,800

 
100,893

 
12,659

 
173,352

Independent Director and Member of the Compensation Committee
 
 
 
 
 
 
 
 
Marshall S. ("Mackie") McCrea, III
 
—

 
2,445,720

 
400,462

 
2,846,182

Chairman of the Board of Directors
 
 
 
 
 
 
 
 
Jamie Welch (5)
 
—

 
—

 
—

 
—

Director
 
 
 
 
 
 
 
 
Thomas P. Mason
 
—

 
583,130

 
73,508

 
656,638

Director
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NOTES TO TABLE:
(1) 
The amounts shown in this column reflect the cash fees earned by directors with respect to the 2016 year.
(2) 
The amounts shown in this column reflect the aggregate grant date fair value of restricted unit awards under the LTIP, calculated in accordance with FASB ASC Topic 718. See Note 14 to our consolidated financial statements for fiscal 2016 for additional detail regarding assumptions underlying the value of these equity awards.
(3) 
The amounts shown in this column reflect the cash payments made to each director during 2016, which were equal to each cash distribution per common unit made by us on our common units during 2016 with respect to each common unit subject to a restricted unit held by such director that has not either vested or been forfeited.
(4) 
Mr. Perry resigned from his position on the Board on December 31, 2016. In connection with that resignation he forfeited all outstanding equity awards that he held on that date, therefore he did not hold any outstanding equity awards as of December 31, 2016. In January 2017, the SXL Compensation Committee approved a cash payment to Mr. Perry of $153,728 representing the fair value of the unit awards forfeited upon his resignation.
(5) 
Mr. Welch resigned from his position on the Board on February 25, 2016 and did not receive an equity grant during 2016.
As of December 31, 2016, Messrs. Anderson, Angelle and Bray each had 10,624 restricted units outstanding, and Messrs. McCrea and Mason had 268,770 and 62,374 restricted units outstanding, respectively.


138


COMPENSATION PRACTICES AS THEY RELATE TO RISK MANAGEMENT
We believe our compensation plans and programs for our NEOs, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to the Partnership. We believe our compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated our compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for the executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment. We generally determine whether, and to what extent, our NEOs receive a cash bonus based on our achievement of specified financial performance objectives as well as the individual contributions of our NEOs to the Partnership's success. We use restricted units rather than unit options for equity awards because restricted units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options "in-the-money." Finally, the time-based vesting over five years for our long-term incentive awards ensures that our employees' interests align with those of our unitholders for the long-term performance of the Partnership.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Messrs. Angelle, McCrea, Anderson, Perry, Bray, and Hennigan served on the Compensation Committee during 2016. Mr. McCrea is an officer of ETE's general partner, and Mr. Hennigan is an officer of our general partner. During 2016, none of the members of the Compensation Committee served as executive officers of any company with respect to which any of our officers served on such company's compensation committee or board of directors, and none of the directors of our general partner served as executive officers of any company with respect to which any of our officers served on such company's compensation committee (or other board committee performing equivalent functions or, in the absence of such committee, the entire board of directors).




139


COMPENSATION COMMITTEE REPORT
The Compensation Committee (the "Committee") of the Board of Directors (the "Board") of Sunoco Partners LLC (the "Company") reviews and approves the Company's executive compensation philosophy; reviews and recommends to the Board for approval the Company's short- and long-term compensation plans; reviews and approves the executive compensation programs and awards; and annually reviews, determines and approves the compensation for the President and Chief Executive Officer and the other executive officers of the Company as described in the Summary Compensation Table and footnotes thereto contained in the Annual Report on SEC Form 10-K of Sunoco Logistics Partners L.P. (the "Partnership"). The Company is the general partner of the Partnership. The Committee Chair reports Committee actions, decisions and recommendations at the meetings of the full Board. The Committee has authority to directly engage and consult outside advisors, experts and others to assist the Committee at the expense of the Partnership.
As required by applicable regulations of the Securities and Exchange Commission, the Committee has reviewed the executive compensation disclosures contained under the caption "Compensation Discussion and Analysis," which are required pursuant to Item 402(b) of SEC Regulation S-K, as amended. As part of this review, the Committee met with management and with such outside consultants and experts as it has deemed necessary or advisable (with and without management present) to discuss the scope and overall quality of the disclosure.
In reliance on the reviews and discussions referred to above, the Committee recommended to the Board, and the Board has approved, the inclusion of the "Compensation Discussion and Analysis" in the Partnership's Annual Report on SEC Form 10-K for the fiscal year ended December 31, 2016, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 24, 2017 by the members of the Compensation Committee of the Board of Directors of Sunoco Partners LLC:

Scott A. Angelle (Chairman)
Steven R. Anderson
Basil Leon Bray
Michael J. Hennigan
Marshall S. ("Mackie") McCrea, III



140


AUDIT COMMITTEE REPORT
The Audit Committee (the "Committee") of the Board of Directors (the "Board") of Sunoco Partners LLC (the "Company") reviews the financial reporting process of Sunoco Logistics Partners L.P. (the "Partnership") on behalf of the Board. The Company is the general partner of the Partnership. The Company's management is responsible for the financial statements and the reporting process, including the internal control over financial reporting. The independent registered public accounting firm is responsible for expressing an opinion on the conformity of the audited financial statements with U.S. generally accepted accounting principles, and an opinion on the effectiveness of the Company's internal control over financial reporting. The Committee monitors and oversees these processes.
The Committee discussed with the Company's internal audit department and independent registered public accounting firm the overall scope and plans for their respective audits. In addition, the Committee has reviewed and discussed with management the audited financial statements and management's and the independent registered public accounting firm's evaluations of the Partnership's system of internal control over financial reporting contained in the 2015 Annual Report on Form 10-K. As part of this review, the Committee met with the General Auditor and the independent registered public accounting firm, with and without management present, to discuss the results of their audits and the overall quality of the Partnership's financial reporting.
As required by the standards of the Public Company Accounting Oversight Board, the Committee has discussed with the independent registered public accounting firm (1) the matters specified in Statement on Auditing Standards No. 61, "Communication with Audit Committees," (Codification of Statements of Auditing Standards, August 2, 2007 AU 380), as amended, as adopted by the Public Company Accounting Oversight Board in Rule 3200T; and (2) the independence of the independent registered public accounting firm from the Partnership and management. The independent registered public accounting firm has provided the Committee the written disclosures and letter concerning independence, pursuant to applicable requirements of the Public Company Accounting Oversight Board. The Committee also considered the compatibility of non-audit services with the independent registered public accounting firm's independence.
In reliance on the reviews and discussions referred to above, the Committee recommended to the Board, and the Board has approved, the inclusion of the audited financial statements and management's report on internal control over financial reporting in the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 24, 2017 by the members of the Audit Committee of the Board of Directors of Sunoco Partners LLC:
Basil Leon Bray (Chairman)
Steven R. Anderson
Scott A. Angelle



141



ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information, as of December 31, 2016, regarding our common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the LTIP to executive officers, directors, and other key employees. The LTIP did not require approval by our limited partners at the time of its adoption in 2002 because the Board adopted the LTIP prior to our initial public offering; however, on December 1, 2015, the limited partners approved the amended and restated LTIP to, among other things, increase in the maximum number of common units reserved and available for delivery with respect to awards under the LTIP by 10 million common units.
The amounts in column (a) of this table reflect only restricted units that have been granted under the LTIP since its inception. No other types of awards have been granted under the LTIP. Each restricted unit shown in the table represents a right to receive (upon vesting and payout) a specified number of our common units. Vesting and payout is conditioned upon achievement of certain length of service goals with us and our affiliates. No value is shown in column (b) of the table, since the restricted units do not have an exercise, or "strike," price. For illustrative purposes, a target payout (i.e., a 100 percent ratio) has been assumed for vesting and payout of all awards. For more information about the LTIP, refer to "Item 11-Executive Compensation."

EQUITY COMPENSATION PLAN INFORMATION
Plan Category
 
(a)

Number of securities to
be issued upon exercise
of  outstanding options,
warrants and rights
 
(b)

Weighted average
exercise price of
outstanding options,
warrants and rights
 
(c)
Number of securities remaining
available for future issuance
under equity compensation
plans, excluding securities
reflected in column (a)
Equity compensation plans approved by security holders
 
3,236,584

 
—

 
8,628,303

Equity compensation plans not
approved by security holders
 
—

 
—

 
—

Total
 
3,236,584

 
—

 
8,628,303




142


Beneficial Ownership Tables
The following table sets forth certain information as of February 22, 2017 regarding the beneficial ownership of our securities by certain beneficial owners, each director and NEO of our general partner, and all directors and NEOs of our general partner as a group. Our general partner knows of no other person not disclosed herein who beneficially owns more than 5 percent of our voting securities. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership securities shown in the table. ETP owns a 99.9 percent equity interest in our general partner, and the remaining 0.10 percent equity interest is owned by ETE Holdings.
Title of Class
Name of Beneficial Owner (1)
 
Number of
Units
Beneficially Owned (2)
 
Percentage of
Class of Units
Beneficially Owned
Common Units
Energy Transfer Partners, L.P.
 
67,061,274

 
20.8
%
 
Tortoise Capital Advisors, L.L.C. (3)
 
23,765,061

 
7.4
%
 
OppenheimerFunds, Inc. (4)
 
18,973,974

 
5.9
%
 
ALPS Advisors, Inc. (5)
 
17,181,855

 
5.3
%
 
Steven R. Anderson
 
16,578

 
*

 
Scott A. Angelle
 
6,578

 
*

 
Basil Leon Bray
 
8,728

 
*

 
Michael J. Hennigan (6)
 
431,952

 
*

 
Thomas P. Mason
 
—

 
*

 
Marshall S. ("Mackie") McCrea, III
 
58,495

 
*

 
Peter J. Gvazdauskas
 
30,025

 
*

 
Kathleen Shea-Ballay
 
58,243

 
*

 
Kurt A. Lauterbach
 
145,119

 
*

 
David R. Chalson
 
90,910

 
*

 
All directors and executive officers as a group (10 persons)
 
846,628

 
*

Class B Units
Energy Transfer Partners, L.P. (7)
 
9,416,196

 
100
%
 
 
 
 
 
 
 
 
 
 
*
Less than 0.5 percent.
NOTES TO TABLE:
(1) 
The address for Messrs. Anderson, Angelle, Bray, Hennigan, Mason, McCrea, Gvazdauskas, Shea-Ballay, Lauterbach, and Chalson is 3807 West Chester Pike, Newtown Square, Pennsylvania 19073. The address for ETP is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225. The principal business address given for Tortoise Capital Advisors, L.L.C. in the Schedule 13G/A filed on February 13, 2017 is 11550 Ash Street, Suite 300, Leawood, Kansas 66211. The principal business address given for OppenheimerFunds, Inc. in the Schedule 13G/A filed on February 6, 2017 is 225 Liberty Street, New York, New York 10281. The principal business address given for ALPS Advisors, Inc. in the Schedule 13G filed on January 26, 2017 is 1290 Broadway, Suite 1100, Denver, CO 80203.
(2) 
Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Exchange Act. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty (60) days.
(3) 
Tortoise Capital Advisors, L.L.C., a Delaware limited liability company, filed a Schedule 13G/A on February 13, 2017 to report that, as of December 31, 2016, it had sole voting and dispositive power over 382,046 common units of the Partnership, shared voting power over 20,989,234 common units of the Partnership, shared dispositive power over 23,383,015 common units of the Partnership, and beneficial ownership of 23,765,061 common units of the Partnership.
(4) 
OppenheimerFunds, Inc., a Colorado corporation, filed a Schedule 13G/A on February 6, 2017 to report that, as of December 31, 2016, it had shared voting and dispositive power over 18,973,974 common units of the Partnership. OppenheimerFunds, Inc. disclaims beneficial ownership of the 18,973,974 common units of the Partnership pursuant to Rule 13d-4 of the Exchange Act.
(5) 
ALPS Advisors, Inc., a Colorado corporation, filed a Schedule 13G on January 26, 2017 to report that, as of December 31, 2016, it had shared voting and dispositive power over 17,181,855 common units of the Partnership. ALPS Advisors, Inc. disclaims beneficial ownership of the 17,181,855 common units of the Partnership pursuant to Rule 13d-4 of the Exchange Act.
(6) 
Mr. Hennigan's spouse has voting and investment power with respect to 14,400 of these units.
(7) 
On October 8, 2015, the Partnership issued 9,416,196 Class B units to ETP. The Class B units have the same terms and conditions of voting rights as the Partnership's common units, but are not entitled to receive quarterly distributions that are made on the Partnership's common units.

143


The following table sets forth certain information regarding beneficial ownership of the common units representing limited partnership interests of ETP as of February 22, 2017 by directors of our general partner, by each NEO and by all directors and NEOs of our general partner as a group. Unless otherwise noted, each individual exercises sole voting or investment power over the ETP common units shown in the table.
Name of Beneficial Owner
 
Common Units of
Energy Transfer
Partners, L.P.
Beneficially Owned (1)
 
Percentage of
Energy Transfer
Partners, L.P
Common Units
Beneficially Owned
Steven R. Anderson
 
10,025

 
*
Scott A. Angelle
 
—

 
*
Basil Leon Bray
 
3,142

 
*
Michael J. Hennigan 
 
—

 
*
Thomas P. Mason (2)
 
10,385

 
*
Marshall S. ("Mackie") McCrea, III (2) (3)
 
351,710

 
*
Peter J. Gvazdauskas
 
—

 
 
Kathleen Shea-Ballay
 
879

 
*
Kurt A. Lauterbach
 
—

 
*
David R. Chalson
 
—

 
*
All directors and executive officers as a group (10 persons)
 
376,141

 
*
 
 
 
 
 
 
 
 
 
 
*
Less than 0.5 percent.
NOTES TO TABLE:
(1) 
Beneficial ownership for the purposes of the foregoing table is defined by Rule 13d-3 under the Exchange Act. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty (60) days.
(2) 
Due to their positions as officers or directors of the general partner of ETE, certain officers and directors of our general partner, who are also officers or directors of ETE's general partner, may be deemed to own beneficially certain limited partnership interests in ETP, held by ETE, to the extent of their respective interests therein. Any such deemed ownership is not reflected in the table.
(3) 
23,640 of these ETP common units are held in the Jacob McCrea 2012 Trust over which Mr. McCrea maintains control.



144



ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
For a discussion of director independence, see Item 10. "Directors, Executive Officers and Corporate Governance."
Our general partner, Sunoco Partners LLC, manages our operations and activities. The membership interests in our general partner are owned 99.9 percent by Energy Transfer Partners, L.P. ("ETP") and 0.1 percent by ETE Common Holdings, LLC ("ETE Holdings"). ETE Holdings is a wholly-owned subsidiary of Energy Transfer Equity, L.P. and an affiliate of ETP.
As of February 22, 2017, ETP, the controlling owner of our general partner, owns a 24.0 percent partnership interest in us, which includes a 1.3 percent general partner interest (through its controlled subsidiary Sunoco Partners LLC), 67.1 million common units, representing a 19.9 percent limited partner interest in us, and 9.4 million Class B units, representing a 2.8 percent limited partner interest in us. The general partner's ability to manage and operate us effectively gives the general partner the ability to control us.
We have various operating and administrative agreements with ETP and its affiliates, including agreements for administrative services, agreements to supply crude oil, NGLs and refined products, agreements to provide pipeline and terminalling services, agreements relating to the Partnership's participation in the Bayou Bridge and Bakken pipeline projects, and agreements in connection with the acquisition of the Marcus Hook Facility. The material agreements with ETP and its affiliates are discussed in more detail under "Management's Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Related Parties."
Concurrently with and subsequent to the closing of our February 2002 IPO, we entered into several agreements with Sunoco, Inc. (R&M) and/or one or more of its affiliates. Some of these agreements have expired or been assigned, extended or replaced. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement, the Inter-Refinery Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, various asset acquisition agreements and other agreements. The material agreements that are still outstanding are discussed in more detail under "Management's Discussion and Analysis of Financial Condition and Results of Operations-Agreements with Related Parties."
Distributions and Payments to the General Partner and Its Affiliates
The following table summarizes the distributions and payments made and to be made by us to the general partner and its affiliates in connection with our ongoing operations and in the case of liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Operational Stage
Payments to the general partner and its affiliates
We paid the general partner an administrative fee, $10 million for the year ended December 31, 2016, for the provision of various general and administrative services for our benefit. In addition, the general partner is entitled to reimbursement for all expenses it incurs on our behalf, including other general and administrative expenses. These reimbursable expenses include the salaries and the cost of employee benefits of employees of the general partner who provide services to us. The general partner has sole discretion in determining the amount of these expenses.

Removal or withdrawal of the general partner
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests as provided in the Partnership Agreement.

Liquidation Stage
Liquidation
Upon liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.




145


Approval and Review of Related Party Transactions
Our Partnership Agreement and the Omnibus Agreement each contain provisions for our Conflicts Committee, comprised of three of our general partner's independent directors, to review transactions with related parties. In some cases, review is required and in others, it is at the discretion of our general partner. Generally, transactions with related parties that are material to us are referred to the Conflicts Committee for review and approval. In determining materiality, our general partner evaluates several factors including the term of the transaction, the capital investment required, and the revenues expected from the transaction.
With respect to other related party transactions, we have in place a Code of Business Conduct and Ethics that is applicable to all directors, officers and employees of the general partner and its subsidiaries, a Code of Ethics for Senior Officers of the general partner and its subsidiaries, and a Conflict of Interest Policy applicable to all directors, officers and employees of the general partner and its subsidiaries. Each of these policies requires the approval by a supervisor, officer, or the Board prior to entering into any related party transaction that could present a potential conflict of interest. Each of the Partnership Agreement, Code of Business Conduct and Ethics, and Code of Ethics for Senior Officers is publicly available on our website.




146


ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The Audit Committee appointed Grant Thornton LLP as our principal accountant to conduct the audit of our financial statements for the years ended December 31, 2016 and 2015.
The following table presents the aggregate fees billed by Grant Thornton LLP for audit and other professional services for the years ended December 31, 2016 and 2015:
 
 
For the Year Ended December 31,
Type of Fee
 
2016
 
2015
 
 
(in millions)
Audit Fees (1) 
 
$
1.5

 
$
1.5

Audit Related Fees
 
—

 
—

Tax Fees
 
—

 
—

All Other Fees
 
—

 
—

 
 
$
1.5

 
$
1.5

(1) 
Audit fees consist of fees for the audit of the Partnership's annual consolidated financial statements, review of consolidated financial statements included in the Partnership's quarterly reports on Form 10-Q, review of registration statements, issuance of comfort letters and consents, and review of documents filed with the SEC. Audit fees also include the fees for the audit of the Partnership's internal control as required by Section 404 of the Sarbanes-Oxley Act of 2002.
Each of the services listed above were approved by the Audit Committee of the general partner's Board prior to their performance. All services rendered by Grant Thornton LLP are performed pursuant to a written engagement letter with the general partner.
The Audit Committee of the general partner's board of directors is responsible for pre-approving all audit services, and permitted non-audit services, to be performed by the independent registered public accounting firm for the Partnership or its general partner. The Committee reviews the services to be performed to determine whether provision of such services potentially could impair the independence of the Partnership's independent registered public accounting firm. The Committee's approval procedures include reviewing a detailed budget for each particular service to be rendered, as well as a description of, and budgeted amounts for, specific categories of anticipated non-audit services. Pre-approval is generally granted for up to one year. Committee approval is required to exceed the budgeted amount for any particular category of services or to engage the independent registered public accounting firm for services not included in the budget. Additional services or specific engagements may be approved, on a case-by-case basis, prior to the independent registered public accounting firm undertaking such services.
Subject to the requirements of applicable law, the Audit Committee may delegate such pre-approval authority to the Audit Committee chairman. However, any pre-approvals granted by the chairman, acting pursuant to such delegated authority, are reviewed by the full membership of the Audit Committee at its next regular meeting. Management of the general partner provides periodic updates to the Audit Committee regarding the extent of any services provided in accordance with this pre-approval process, as well as the cumulative fees incurred to date for all non-audit services, to ensure that such services are within the parameters approved by the Audit Committee.




147



PART IV
 
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as part of this report:
(a)
The financial statements and notes thereto are included in Item 8. Financial Statements and Supplementary Data.
(b)
All financial statement schedules required are included in the financial statements or notes thereto.
(c)
Exhibits:
 
 
 
Exhibit
No.
 
Description
 
 
2.1*
 
Asset and Membership Interest Purchase and Sale Agreement between Texon Distributing L.P. d/b/a Texon L.P. and Butane Acquisition I LLC, dated as of June 25, 2010 (incorporated by reference to Exhibit 2.1 of Form 10-Q, File No. 1-31219, filed August 4, 2010)
 
 
2.1.1*
 
Schedules and Exhibits to Asset and Membership Interest Purchase and Sale Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(b)(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, File No. 1-31219, filed August 4, 2010)
 
 
 
2.2*
 
Membership Interest Purchase Agreement, dated as of August 2, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC (incorporated by reference to Exhibit 2.1 of Form 10-Q, File No. 1-31219, filed November 9, 2016)

 
 
 
2.2.1*
 
Schedules and Exhibits to Membership Interest Purchase Agreement omitted from this filing. Registrant hereby undertakes, pursuant to Regulation S-K Item 601(b)(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 10-Q, File No. 1-31219, filed November 9, 2016)

 
 
 
2.2.2
 
Amendment to the Membership Interest Purchase Agreement, dated as of December 15, 2016, by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC
 
 
2.3*
 
Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K of SXL filed with the SEC on November 21, 2016)

 
 
 
2.3.1*
 
Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K of SXL filed with the SEC on December 21, 2016)

 
 
 
3.1*
 
Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1 Registration Statement, File No. 333-71968, filed October 22, 2001)
 
 
3.1.1*
 
Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 1, 2015)

 
 
 
3.2*
 
Certificate of Limited Partnership of Sunoco Logistics Partners Operations L.P. (incorporated by reference to Exhibit 3.1 of Amendment No. 1 to Form S-1 Registration Statement, File No. 333-71968, filed December 18, 2001)
 
 
3.3*
 
First Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners Operations L.P., dated as of February 8, 2002 (incorporated by reference to Exhibit 3.4 of Form 10-K, File No. 1-31219, filed April 1, 2002)
 
 
3.4*
 
Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed January 28, 2010)
 
 
 
 
 
 
 
 

148


 
 
 
Exhibit
No.
 
Exhibit
No.
 
 
3.4.1*
 
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of July 1, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed July 5, 2011)
 
 
3.4.2*
 
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of November 21, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 28, 2011)
 
 
 
3.4.3*
 
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of June 12, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed June 17, 2014)
 
 
 
3.4.4*
 
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of July 30, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed August 4, 2014)
 
 
 
3.4.5 *
 
Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of August 28, 2015 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-31219, filed September 1, 2015)

 
 
 
3.4.6*
 
Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of October 8, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed October 15, 2015)

 
 
 
3.4.7*
 
Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of September 26, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 26, 2016)

 
 
 
3.5*
 
Fifth Amended and Restated Limited Liability Company Agreement of Sunoco Partners LLC, dated October 31, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 1, 2013)
4.1*
 
Indenture, dated as of December 16, 2005, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, Sunoco Partners Marketing & Terminals L.P., as subsidiary guarantor, Sunoco Pipeline L.P., as subsidiary guarantor, and Citibank, N.A., as trustee (incorporated by reference to Exhibit 4.4 of Registration Statement on Form S-3, File No. 333-130564, filed December 21, 2005)
 
 
 
4.1.1*
 
First Supplemental Indenture, dated as of May 8, 2006, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, Sunoco Partners Marketing & Terminals L.P., as subsidiary guarantor, Sunoco Pipeline L.P., as subsidiary guarantor, and Citibank, N.A., as trustee (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed May 8, 2006)

 
 
 
4.1.2*
 
Second Supplemental Indenture, dated as of February 6, 2009, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed February 6, 2009)

 
 
 
4.1.3*
 
Third Supplemental Indenture, dated as of February 12, 2010, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed February 12, 2010)

 
 
 
4.1.4*
 
Fourth Supplemental Indenture, dated as of February 12, 2010, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed February 12, 2010)

 
 
 
4.1.5*
 
Fifth Supplemental Indenture, dated as of August 2, 2011, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed August 2, 2011)

 
 
 
 
 
 
 
 
 

149


 
 
 
Exhibit
No.
 
Description
 
 
4.1.6*
 
Sixth Supplemental Indenture, dated as of August 2, 2011, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed August 2, 2011)

 
 
 
4.1.7*
 
Seventh Supplemental Indenture, dated as of January 10, 2013, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No.1-31219, filed January 10, 2013)
 
 
4.1.8*
 
Eighth Supplemental Indenture, dated as of January 10, 2013, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No.1-31219, filed January 10, 2013)
 
 
 
4.1.9*
 
Ninth Supplemental Indenture, dated as of April 3, 2014, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed April 3, 2014)
 
 
 
4.1.10*
 
Tenth Supplemental Indenture, dated as of April 3, 2014, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed April 3, 2014)
 
 
 
4.1.11*
 
Eleventh Supplemental Indenture, dated as of November 17, 2014, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2014)
 
 
 
4.1.12*
 
Twelfth Supplemental Indenture, dated as of November 17, 2015, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed November 17, 2015)
 
 
 
4.1.13*
 
Thirteenth Supplemental Indenture, dated as of November 17, 2015, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2015)
 
 
 
4.1.14*
 
Fourteenth Supplemental Indenture, dated as of July 12, 2016, by and among Sunoco Logistics Partners Operations L.P., as issuer, Sunoco Logistics Partners L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed July 12, 2016)
 
 
 
4.2*
 
Form of Subordinated Indenture (incorporated by reference to Exhibit 4.8 of Registration Statement on Form S-3, File No. 333-103710, filed March 10, 2003)

 
 
 
4.3*
 
Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of December 1, 2015 (incorporated by reference to Exhibit A to the Definitive Proxy Statement on Schedule 14A, filed October 21, 2015)

 
 
 
10.1*
 
Contribution, Conveyance and Assumption Agreement, dated as of February 8, 2002, among Sunoco, Inc., Sun Pipe Line Company of Delaware, Sunoco, Inc. (R&M), Atlantic Petroleum Corporation; Sunoco Texas Pipe Line Company, Sun Oil Line of Michigan (Out) LLC, Mid-Continent Pipe Line (Out) LLC, Sun Pipe Line Services (Out) LLC, Atlantic Petroleum Delaware Corporation, Atlantic Pipeline (Out) L.P., Sunoco Partners LLC, Sunoco Partners Lease Acquisition & Marketing LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners GP LLC, Sunoco Pipeline L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Mid-Con (In) LLC, Atlantic (In) L.P., Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners Operations GP LLC, Atlantic R&M (In) L.P., Sun Pipe Line Services (In) L.P., Sunoco Michigan (In) LLC, Atlantic (In) LLC, Sunoco Logistics Pipe Line GP LLC, Sunoco R&M (In) LLC, and Atlantic Refining & Marketing Corp. (incorporated by reference to Exhibit 10.4 of Form 10-K, File No. 1-31219, filed April 1, 2002)
 
 
 
 
 
 

150


 
 
 
Exhibit
No.
 
Description
 
 
10.2*
 
Omnibus Agreement, dated as of February 8, 2002, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sunoco Logistics Pipe Line Company of Delaware, Atlantic Petroleum Corporation, Sunoco Texas Pipe Line Company, Sun Pipe Line Services (Out) LLC, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.5 of Form 10-K, File No. 1-31219, filed April 1, 2002)
 
 
 
10.2.1*
 
Amendment No. 2011-1 to Omnibus Agreement, dated as of February 22, 2011, and effective January 1, 2011, by and among Sunoco, Inc., Sunoco, Inc. (R&M), Sun Pipe Line Company of Delaware LLC, Atlantic Petroleum Corporation, Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Pipeline L.P. and Sunoco Partners LLC (incorporated by reference to Exhibit 10.6.1 of Form-K, File No. 1-31219 filed February 23, 2011)
10.3*
 
Amended and Restated Treasury Services Agreement, dated as of November 26, 2003, by and among Sunoco, Inc., Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Pipeline L.P., and Sunoco Partners Marketing & Terminals L.P. (incorporated by reference to Exhibit 10.7.1 of Form 10-K, File No. 1-31219, filed March 4, 2004)
 
 
 
10.4*
 
Intellectual Property and Trademark License Agreement, dated as of February 8, 2002, among Sunoco, Inc., Sunoco, Inc. (R&M), Sunmarks, Inc., Sunoco Logistics Partners L.P., Sunoco Logistics Partners Operations L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P., and Sunoco Partners LLC (incorporated by reference to Exhibit 10.8 of Form 10-K, File No. 1-31219, filed April 1, 2002)
 
 
 
10.5*
 
Inter-Refinery Pipeline Lease, dated as of February 8, 2002, between Sunoco Pipeline L.P., and Sunoco, Inc. (R&M) (incorporated by reference to Exhibit 10.9 of Form 10-K, File No. 1-31219, filed April 1, 2002)
 
 
 
10.6.1*
 
Form of Time-Vested Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9.2 of Form 10-K, File No. 1-31219, filed March 1, 2013)
 
 
10.6.2*
 
Michael J. Hennigan and Marshall S. (Mackie) McCrea, III Form of December 2014 Time-Vested Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6.2 of Form 10-K, File No. 1-31219, filed February 26, 2016)

 
 
 
10.6.3*
 
Form of Time-Vested Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of December 1, 2015 (incorporated by reference to Exhibit 10.6.3 of Form 10-K, File No. 1-31219, filed February 26, 2016)

 
 
 
10.7*
 
Sunoco Partners LLC Amended and Restated Annual Short-Term Incentive Bonus Plan, dated as of January 1, 2014 (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed May 8, 2014)
 
 
 
10.8**
 
Crude Oil Pipeline Throughput and Deficiency Agreement between Motiva Enterprises LLC and Sunoco Pipeline L.P., dated as of December 15, 2006 (incorporated by reference to Exhibit 10.19 of Form 10-K, File No. 1-31219, filed February 23, 2007)
 
 
10.9**
 
Marine Dock and Terminalling Agreement between Motiva Enterprises LLC and Sunoco Partners Marketing & Terminals L.P., dated as of December 15, 2006 (incorporated by reference to Exhibit 10.20 of Form 10-K, File No. 1-31219, filed February 23, 2007)
 
 
 
10.10*
 
Membership Interest Purchase Agreement, effective as of July 27, 2006, between Sunoco, Inc. and Sunoco Pipeline Acquisition LLC (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed August 2, 2006)
 
 
10.11**
 
Product Terminal Services Agreement, dated as of May 1, 2007, among Sunoco, Inc. (R&M) and Sunoco Partners Marketing & Terminals L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed July 31, 2007)
 
 
10.11.1*
 
Letter Agreement, dated January 19, 2012, amending Product Terminal Services Agreement (incorporated by reference to Exhibit 10.17.1 of Form 10-K, File No. 1-31219, filed February 24, 2012)
 
 
10.12*
 
Repurchase Agreement between Sunoco Logistics Partners L.P. and Sunoco Partners LLC, dated January 26, 2010 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-31219, filed January 28, 2010)
 
 
 
10.13*
 
Contribution Agreement, dated as of June 29, 2011, to be effective July 1, 2011, by and among Sunoco, Inc. (R&M), Sunoco Logistics Partners L.P., and certain subsidiaries and affiliates of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 10.1 of Form 10-Q/A, File No. 1-31219, filed August 8, 2011)
 
 
 

151


 
 
 
Exhibit
No.
 
Description
 
 
10.14*
 
Letter Agreement dated November 2, 2011, by and between Sunoco Partners LLC and Michael J. Hennigan, President and Chief Operating Officer (incorporated by reference to Exhibit 10.3 of Form 10-Q, File No. 1-31219, filed November 3, 2011)
 
 
 
10.15*
 
Letter Agreement with Michael J. Hennigan, President and Chief Executive Officer, dated October 4, 2012 (incorporated by reference to Exhibit 10.3 of Form 10-Q, File No. 1-31219, filed November 8, 2012)
 
 
 
10.16*
 
Exchange Agreement, dated as of September 16, 2015, between Energy Transfer Partners, L.P., La Grange Acquisition, L.P., Sunoco Logistics Partners L.P. and Sunoco Pipeline L.P. for membership interest in Bakken Holdings Company LLC (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-31219, filed October 15, 2015)
 
 
 
10.17*
 
Unitholder Agreement, dated as of October 8, 2015, between Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-31219, filed October 15, 2015)

 
 
 
10.18*
 
$2,500,000,000 Amended and Restated Credit Agreement, dated as of March 20, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swingline Lender and a LC Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed May 7, 2015)

 
 
 
10.19*
 
Amendment No. 1 to the $2,500,000,000 Amended and Restated Credit Agreement, dated as of June 29, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swing Line Lender and a LC Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed August 6, 2015)

 
 
 
10.20**
 
Agreement and Plan of Merger, dated as of April 29, 2012 by and among Sunoco, Inc., Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-31219, filed May 2, 2012)

 
 
 
10.21*
 
Energy Transfer Partners Deferred Compensation Plan for Former Sunoco Executives effective October 5, 2012 (incorporated by reference to Exhibit 10.21 of Form 10-K, File No. 1-31219, filed February 26, 2016)
 
 
 
12.1
  
Statement of Computation of Ratio of Earnings to Fixed Charges
 
 
 
14.1*
  
Code of Ethics for Senior Officers (incorporated by reference to Exhibit 14.1 of Form 10-K, File No. 1-31219, filed March 4, 2004)
 
 
 
21.1
  
Subsidiaries of Sunoco Logistics Partners L.P.
 
 
 
23.1
  
Consent of Grant Thornton LLP
 
 
24.1
  
Power of Attorney
 
 
31.1
  
Officer Certification Pursuant to Exchange Act Rule 13a-14(a)
 
 
31.2
  
Officer Certification Pursuant to Exchange Act Rule 13a-14(a)
 
 
32.1
  
Officer Certification Pursuant to Exchange Act Rule 13a-14(b) and 18 U.S.C. § 1350
 
 
 
101.1
  
The following consolidated financial information from Sunoco Logistics Partners L.P.'s Annual Report on Form 10-K for the year ended December 31, 2016 formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Comprehensive Income; (ii) the Consolidated Balance Sheets; (iii) the Consolidated Statements of Cash Flows; (iv) the Consolidated Statements of Equity; and, (v) the Notes to the Consolidated Financial Statements.
*
Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference.
**
Confidential status has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed February 23, 2007. Such provisions have been separately filed with the Commission.
 

152


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
Sunoco Logistics Partners L.P.
(Registrant)
 
 
BY:
Sunoco Partners LLC (its General Partner)
 
 
By:
/s/ PETER J. GVAZDAUSKAS
 
 
 
 
 
Peter J. Gvazdauskas
 
 
Chief Financial Officer and Treasurer
February 24, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by or on behalf of the following persons on behalf of the registrant and in the capacities indicated on February 24, 2017.
 
 
 
STEVEN R. ANDERSON*
 
THOMAS P. MASON*
 
 
 
Steven R. Anderson
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
  
Thomas P. Mason
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
 
 
 
SCOTT A. ANGELLE*
 
MARSHALL S. MCCREA III*
 
 
 
Scott A. Angelle
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
  
Marshall S. McCrea III
Director (Chairman) of
Sunoco Partners LLC, General Partner of
Sunoco Logistics Partners L.P.
 
 
 
BASIL LEON BRAY*
 
MICHAEL D. GALTMAN*
 
 
 
Basil Leon Bray
Director of Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
  
Michael D. Galtman
Controller and Chief Accounting Officer of
Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
(Principal Accounting Officer)
 
 
 
MICHAEL J. HENNIGAN*
 
 
 
 
 
Michael J. Hennigan
Director, President and Chief Executive Officer of
Sunoco Partners LLC,
General Partner of
Sunoco Logistics Partners L.P.
(Principal Executive Officer)
 
 
 
 
 

153


ITEM 16.
FORM 10-K SUMMARY
None.


154