Edgar Filing: SUNOCO LOGISTICS PARTNERS L.P.

Large accelerated filer

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

2013 Form 10-K - XBRL Copy

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, 2013



¨	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.)

1818 Market Street, Suite 1500, Philadelphia, PA		19103
(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 partnership interests		New York Stock Exchange
Senior Notes 8.75%, due February 15, 2014		New York Stock Exchange
Senior Notes 6.125%, due May 15, 2016		New York Stock Exchange
Senior Notes 5.50%, due February 15, 2020		New York Stock Exchange
Senior Notes 4.65%, due February 15, 2022		New York Stock Exchange
Senior Notes 3.45%, due January 15, 2023		New York Stock Exchange
Senior Notes 6.85%, due February 15, 2040		New York Stock Exchange
Senior Notes 6.10%, due February 15, 2042		New York Stock Exchange
Senior Notes 4.95%, due January 15, 2043		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. ý

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.

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 $4.5 billion as of June 28, 2013, based on $63.95 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date. At February 26, 2014, the number of the registrant’s Common Units outstanding were 103,974,752.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS




PART I		3
ITEM 1.	BUSINESS	3
ITEM 1A.	RISK FACTORS	17
ITEM 1B.	UNRESOLVED STAFF COMMENTS	28
ITEM 2.	PROPERTIES	28
ITEM 3.	LEGAL PROCEEDINGS	29
ITEM 4.	MINE SAFETY DISCLOSURES	29

PART II		30
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	30
ITEM 6.	SELECTED FINANCIAL DATA	31
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	55
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	57
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	103
ITEM 9A.	CONTROLS AND PROCEDURES	103
ITEM 9B.	OTHER INFORMATION	103

PART III		104
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	104
ITEM 11.	EXECUTIVE COMPENSATION	108
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS	141
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	144
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	146

PART IV		147
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	147

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 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 supply of or demand for crude oil, refined petroleum products and natural gas liquids ("NGLs") that impact demand for our pipeline, terminalling and storage services;


•	Changes in the short-term and long-term demand for crude oil, refined petroleum products and NGLs we buy and sell;


•	An increase in the competition encountered by our terminals, pipelines and crude oil and refined products 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 tax, safety, environmental and employment laws;


•	Changes in regulations governing 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 ability of Energy Transfer Partners, L.P. to successfully integrate our operations and employees, and realize anticipated synergies;


•	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 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 capital markets 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.

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, refined products, and natural gas liquids ("NGLs"). The principal executive offices of Sunoco Partners LLC, our general partner, are located at 1818 Market Street, Suite 1500, Philadelphia, Pennsylvania 19103 (telephone (866) 248-4344). Our website address is www.sunocologistics.com.

(b) Financial Information about Segments

See Part II, Item 8. "Financial Statements and Supplementary Data."

We are a Delaware limited partnership which is principally engaged in the transport, terminalling and storage of crude oil, refined products and NGLs. In addition to logistics services, we also own acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products and NGLs. Our portfolio of geographically diverse assets earns revenues in more than 30 states located throughout the United States. Our reporting segments are as follows:

•

The Crude Oil Pipelines transport crude oil principally in Oklahoma and Texas. The segment contains approximately 4,900 miles of crude oil trunk pipelines for high-volume, long-distance transportation, and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines. The segment includes controlling financial interests in the West Texas Gulf Pipe Line Company ("West Texas Gulf") and Mid-Valley Pipeline Company ("Mid-Valley").


•	The Crude Oil Acquisition and Marketing business gathers, purchases, markets and sells crude oil principally in the mid-continent United States. The segment utilizes our proprietary fleet of approximately 300 crude oil transport trucks and approximately 130 crude oil truck unloading facilities, as well as third-party assets.

•

The Terminal Facilities operate with an aggregate storage capacity of approximately 46 million barrels. The segment includes the 22 million barrel Nederland, Texas crude oil terminal; the 5 million barrel Eagle Point, New Jersey refined products and crude oil terminal; the 5 million barrel Marcus Hook, Pennsylvania refined products and NGL facility (the "Marcus Hook Facility"); 39 active refined products marketing terminals located in the northeast, midwest and southwest United States; and several refinery terminals located in the northeast United States.


•	The Refined Products Pipelines consist of approximately 2,500 miles of refined products pipelines, and joint venture interests in four refined products pipelines in the northwest and midwest United States. This segment includes a controlling financial interest in Inland Corporation ("Inland").

In 2013, we continued to expand our operations into pipeline transportation, storage and acquisition and marketing of NGLs in the northeastern United States with the successful launch of our pipeline project to deliver ethane from the Marcellus Shale Basin to Ontario ("Project Mariner West") and the acquisition of the Marcus Hook facility. Operational results from these activities have been included in our Refined Products Pipelines and Terminal Facilities segments, respectively. While these activities have not had a material impact on our operational results to date, we will continue to expand our NGL platform through previously announced growth projects that are expected to commence operations throughout 2014 and 2015.

Our primary business strategies focus on generating stable cash flows, increasing pipeline and terminal throughput, utilizing our crude oil gathering assets to maximize value for producers, pursuing economically accretive organic growth opportunities and improving operating efficiencies. We believe that the effective execution of these strategies will result in continued increases in distributions to our unitholders.

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 and refined product pipeline, 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.

Crude Oil Pipelines

The crude oil pipelines consist of approximately 5,400 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States. These pipelines include controlling financial interests in the Mid-Valley and West Texas Gulf pipelines. Our pipelines access several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma ("Cushing"), as well as 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.

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,
	2013	2012	2011
Pipeline throughput (thousands of barrels per day ("bpd"))	1,866	1,556	1,587

Southwest United States

Our pipelines in the southwest United States include approximately 2,950 miles of crude oil trunk pipelines and approximately 300 miles of crude oil gathering pipelines in Texas. Revenues are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the Railroad Commission of Texas ("Texas R.R.C.") and the Federal Energy Regulatory Commission ("FERC").

We also own and operate a crude oil pipeline and gathering system in Oklahoma. This system contains approximately 850 miles of crude oil trunk pipelines and approximately 200 miles of crude oil gathering pipelines. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. Revenues are generated on our Oklahoma system from tariffs paid by shippers utilizing our transportation services. We file these tariffs with the Oklahoma Corporation Commission ("OCC") and the FERC. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing business is the primary shipper on our Oklahoma system.

In the third quarter 2013, we entered into an agreement to form SunVit Pipeline LLC ("SunVit"), a joint venture with Vitol, Inc. ("Vitol"), in which each party will maintain a 50 percent ownership interest. SunVit will construct and own a crude oil pipeline, which will originate in Midland, Texas and run to Garden City, Texas. The new pipeline will connect into our Permian Express 2 pipeline project and will provide additional takeaway capacity from the Permian Basin. SunVit is expected to commence operations in 2015.

Midwest United States

We have a controlling financial interest in the Mid-Valley pipeline system which owns approximately 1,000 miles of crude oil pipelines that originate in Longview, Texas and pass through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio, and terminate in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwest United States.

In addition, we own approximately 100 miles of 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 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.

Revenues are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC.

Crude Oil Acquisition and Marketing

Our crude oil acquisition and marketing 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 300 crude oil transport trucks and approximately 130 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets. Specifically, the 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 on our pipelines and trucks or, when necessary or cost effective, pipelines 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.

We completed the following acquisition in the crude oil acquisition and marketing business since December 31, 2010:


•	Crude Oil Acquisition and Marketing Business—In August 2011, we acquired a crude oil acquisition and marketing business from Texon L.P. ("Texon") which consisted of a 75 thousand bpd crude oil purchasing business and gathering assets in 16 states, primarily in the mid-continent United States.

The crude oil acquisition and marketing operations 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 operations. The operating results of the crude oil acquisition and marketing operations are dependent on our ability to sell crude oil at a price in excess of our aggregate cost. Our crude oil acquisition and marketing 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 operations 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 for this segment. 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.

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.

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's 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 requirement 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, 2013, we purchased 339 thousand bpd from approximately 3 thousand producers who operate approximately 54 thousand active leases. We also undertook 410 thousand bpd of exchanges and bulk purchases during the same period.

The following table shows our average daily volume for crude oil lease purchases and sales and other exchanges and bulk purchases for the years presented:



	Year Ended December 31,
	2013	2012	2011
	(in thousands of bpd)
Lease purchases:
Available for sale	332	283	215
Exchanged	7	6	9
Other exchanges and bulk purchases	410	384	439
Total Purchases	749	673	663

Bulk Sales	419	342	281
Exchanges:
Purchased at the lease	7	6	9
Other	321	321	370
Total Sales	747	669	660

Crude Oil Price Volatility

Crude oil commodity prices have historically been volatile and cyclical. Profitability from our Crude Oil Acquisition and Marketing segment 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 Crude Oil Acquisition and Marketing business, which may be optimized and enhanced when there is a high level of market volatility. Integration between our crude oil acquisition and marketing assets, crude oil pipelines and terminal facilities allows us to further improve upon earnings during periods when there are favorable basis differentials between various types of crude oils. 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 that is neither in pronounced backwardation nor contango), represents the most difficult environment for our marketing activities.

Crude Oil Trucking

We own approximately 130 crude oil truck unloading facilities in the mid-continent United States with the majority located on our pipeline system. Approximately 400 crude oil truck drivers are employed by an affiliate of our general partner and we own and operate a proprietary fleet of approximately 300 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.

Terminal Facilities

Our terminal facilities operate with an aggregate storage capacity of approximately 46 million barrels. Since December 31, 2010, we completed the following acquisitions in the terminalling business:

•

Marcus Hook Facility—In the second quarter 2013, we acquired Sunoco's Marcus Hook facility and related assets (the "Marcus Hook Facility"). The acquisition included terminalling and storage assets with a capacity of approximately 5 million barrels located in Pennsylvania and Delaware, including approximately 2 million barrels of NGL storage capacity in underground caverns, as well as commercial agreements.

•

East Boston Terminal—In September 2011, we acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips. The terminal is the sole service provider to Logan International Airport under a long-term contract to provide jet fuel. The terminal includes a 10-bay truck rack and total active storage capacity for this facility is approximately 1 million barrels.


•	Eagle Point Tank Farm—In July 2011, we acquired the Eagle Point tank farm and related assets from Sunoco. The tank farm is located in Westville, New Jersey and consists of approximately 5 million barrels of active storage for clean products and dark oils.

Refined Products Terminals

Our 39 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 are facilities where products are transferred to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. 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. Typically, our refined products terminal facilities consist of multiple storage tanks and are 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, we generate revenues by charging customers fees for blending services, including ethanol and biodiesel blending, injecting additives, and filtering jet fuel. Our refined products pipelines supply 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,
	2013	2012	2011
Refined products throughput (thousands of bpd)	431	487	492

The following table outlines the number of active terminals and storage capacity by state:



State	Number of Terminals	Storage Capacity
		(thousands of barrels)
Indiana	1	206
Louisiana	1	161
Maryland	1	710
Massachusetts	1	1,144
Michigan	3	760
New Jersey	3	650
New York ⁽¹⁾	4	920
Ohio	7	957
Pennsylvania	13	1,743
Texas	4	548
Virginia	1	403
Total	39	8,202


⁽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.

Refined Products Acquisition and Marketing

Our refined products acquisition and marketing activities include the acquisition, blending, marketing and selling of refined products and NGLs 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 refined product terminals, as well as at third-party facilities. We have also commenced operations in the NGL market with the acquisition of the Marcus Hook Facility (see below). 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 refined 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 refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices.

Nederland Terminal

The Nederland Terminal, which is 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. The terminal receives, stores, and distributes crude oil, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 22 million barrels in approximately 130 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 three barge berths. The five ship docks are capable of receiving over 2 million bpd of crude oil. In addition to our Crude Oil Pipelines, the terminal can also receive crude oil through a number of other pipelines, including:


•	the Cameron Highway pipeline, which is jointly owned by Enterprise Products and Genesis Energy;


•	the ExxonMobil Pegasus pipeline;


•	the Department of Energy ("DOE") Big Hill pipeline; and


•	the DOE West Hackberry pipeline.

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 400 million barrels.

The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge, ship, rail, or truck. In total, the terminal is capable of delivering over 2 million bpd of crude oil to our Crude Oil Pipelines or a number of third-party pipelines including:


•	the ExxonMobil pipeline to its Beaumont, Texas refinery;


•	the DOE pipelines to the Big Hill and West Hackberry Strategic Petroleum Reserve caverns;


•	the Valero pipeline to its Port Arthur, Texas refinery; and


•	the Total pipelines to its Port Arthur, Texas refinery.

The table below summarizes the total average daily throughput for the Nederland Terminal in each of the years presented:



	Year Ended December 31,
	2013	2012	2011
Crude oil and refined products throughput (thousands of bpd)	932	724	757

Revenues are generated at the Nederland Terminal primarily by providing term or spot storage services and throughput capabilities to a number of customers.

Fort Mifflin Terminal Complex

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. In connection with Sunoco's decision to exit the refining business, we recognized a charge in the fourth quarter 2011 related to the Fort Mifflin Terminal Complex for asset write-downs and regulatory obligations which would have been incurred if certain terminal assets were permanently idled, as substantially all of the revenues from the Fort Mifflin Terminal Complex are derived from the Philadelphia refinery. In September 2012, Sunoco completed the formation of Philadelphia Energy Solutions ("PES"), a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. In connection with this transaction, we entered into a new 10-year agreement to provide terminalling services to PES at the Fort Mifflin Terminal Complex. In addition, we reversed certain regulatory obligations that were no longer expected to be incurred as a result of the formation of PES.

The Fort Mifflin Terminal contains two ship docks with 40-foot freshwater drafts and a total storage capacity of approximately 570 thousand barrels. Crude oil and some refined products enter 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 primary crude oil storage terminal for the Philadelphia refinery. 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.

The table below summarizes the average daily number of barrels of crude oil and refined products delivered to the Philadelphia refinery from the Fort Mifflin Terminal Complex in each of the years presented:



	Year Ended December 31,
	2013	2012	2011
	(in thousands of bpd)
Crude oil throughput	258	293	267
Refined products throughput	—	13	9
Total	258	306	276

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.

Marcus Hook Facility

In 2013, we acquired Sunoco's Marcus Hook Facility. The acquisition included terminalling and storage assets with a capacity of approximately 5 million barrels located in Pennsylvania and Delaware, including approximately 2 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 NGL storage and terminalling services to both affiliates and third-party customers, we also provide our customers with the use of industrial space and equipment at the facility, as well as logistical, utility and infrastructure services.

Eagle Point Terminal

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 ships or barges to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. We acquired the tank farm, which formerly served Sunoco's idled Eagle Point refinery, from Sunoco in 2011 to compliment the storage and distribution services offered by our existing dock and truck loading facilities. The tank farm has a total active storage capacity of approximately 5 million barrels and can receive crude oil and refined products via barge, pipeline and rail. The terminal can deliver via barge, truck, rail or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage for clean products and dark oils.

The table below summarizes the total average daily throughput for the Eagle Point Terminal in each of the years presented:



	Year Ended December 31,
	2013	2012	2011
	(in thousands of bpd)
Crude oil throughput	20	14	4
Refined products throughput	79	42	30
Total	99	56	34

Inkster Terminal

The Inkster Terminal, located near Detroit, Michigan, contains eight salt caverns with a total storage capacity of approximately 975 thousand barrels. We use the Inkster Terminal's storage in connection with our Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of liquefied petroleum gases ("LPGs") from Canada and a refinery in Toledo, which was sold by Sunoco to PBF Holding Company LLC in the first quarter 2011. The terminal can receive and ship LPGs in both directions at the same time and has a propane truck loading rack.

Refined Products Pipelines

We own and operate approximately 2,500 miles of refined products pipelines in several regions of the United States. The refined products pipelines primarily transport refined products from refineries in the northeast, midwest and southwest United States to markets in New York, New Jersey, Pennsylvania, Ohio, Michigan and Texas. These operations include our controlling financial interest in Inland, which owns approximately 350 miles of refined products pipeline.

The products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), and LPGs (such as propane and butane). In addition, certain of our pipelines in this segment transport NGLs from processing and fractionation areas to end-user markets. Rates for shipments on the Refined Products Pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission ("PA PUC"), among other state regulatory agencies.

Since December 31, 2010, we completed the following acquisition related to our refined products pipelines:

•

Inland Corporation—In May 2011, we acquired an 83.8 percent equity interest in Inland from Sunoco and Shell Oil Company. Inland is the owner of approximately 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets within the state. As we have a controlling financial interest in Inland, the joint venture is reflected as a consolidated subsidiary in our consolidated financial statements. We assumed operatorship of the pipeline during 2012.

The following table shows the average shipments on the refined products pipelines in each of the years presented. Average shipments represent the average revenue-generating pipeline throughput:



	Year Ended December 31,
	2013	2012	2011
Pipeline throughput (thousands of bpd)⁽¹⁾⁽²⁾	571	582	522


⁽¹⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

⁽²⁾

In May 2011, we acquired a controlling financial interest in Inland and we accounted for the entity as a consolidated subsidiary from the date of acquisition. Average volumes for the year ended December 31, 2011 of 88 thousand bpd have been included in the consolidated total. From the date of acquisition, this pipeline had actual throughput of 140 thousand bpd for the year ended December 31, 2011.

The mix of refined 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 the 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.

Joint Ventures

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⁾	9.4	%	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, 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.

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 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.

Competition

Crude Oil Pipelines

Our Crude Oil Pipelines face competition from a number of major oil companies and other smaller entities. Competition among common carrier pipelines is based primarily on transportation charges, access to crude oil supply and market demand, which may be negatively impacted by changes in refiners' supply sources. Additional investment in rail infrastructure to transport crude oil has also provided increased competition for crude oil pipelines.

Crude Oil Acquisition and Marketing

Our competitors include other crude oil pipeline companies; the major integrated oil companies, their marketing affiliates and independent gatherers; banks that have established trading platforms; and brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of crude oil. Crude oil acquisition and marketing competitive factors include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Terminal Facilities

Our 39 active refined products terminals located in the northeast, midwest and southwest 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. We are not aware of any direct competitors in the butane blending business in the United States and our patents provide us exclusive use and control over the distribution of our butane blending technology.

Throughput at the Nederland Terminal is primarily related to third-party customers. The primary competitors of the Nederland Terminal are its refinery customers' docks and other terminal facilities located in the Beaumont, Texas area.

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."

Refined Products Pipelines

A substantial portion of the Refined Products Pipelines are located in the northeast United States and were constructed or acquired to distribute refined products to Sunoco's retail network. While Sunoco completed the exit from its refining business in 2012, Sunoco continues to operate its retail marketing network and we expect that Sunoco will continue to utilize our Refined Products Pipelines as an efficient means to meet its retail marketing demand. For further information on the impact, see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations – Agreements with Related Parties."

Generally, pipelines are the lowest-cost method for long-haul, overland movement of refined products. Therefore, the most significant competitors for large volume shipments in these areas are other pipelines. 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 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. Although it is unlikely that a pipeline system comparable in size and scope to the northeast and midwest portion of the Refined Products Pipelines will be built in the foreseeable future, new pipelines (including pipeline segments that connect with existing pipeline systems) could be built to effectively compete with it in particular locations.

In the southwest United States, our MagTex refined products pipeline system faces competition from existing third-party-owned and joint-venture pipelines that have excess capacity. Gulf Coast refinery expansions could justify the construction of a new pipeline that would compete with our refined products pipeline system in the southwest. However, at this time, we believe the existing pipelines have the capacity to satisfy expected future demand.

In addition to competition from other pipelines, we face competition from trucks that deliver refined products in a number of areas that we serve. While their costs may not be competitive for longer hauls or large volume shipments, trucks compete effectively for incremental and marginal volume in many areas where such means of transportation are prevalent. The availability of truck transportation places a significant competitive constraint on our ability to increase tariff rates.

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 Risk Based 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 believe 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 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"). 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 IPO date. 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 and Inland, 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, 2013, 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.

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 ("GHGs"). 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, refined products or NGL 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 Act's ("CERCLA") and 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, refined products or NGLs. 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.

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 refined products and crude oil 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 several petroleum and refined product 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. 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, 2013. We have implemented an extensive inspection program to prevent releases of crude oil, refined products or NGLs 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 Texas R.R.C., the PA PUC, and the OCC. 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.

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 title to these properties is 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 2,000 people at December 31, 2013 who provide direct support to the operations. Labor unions or associations represented approximately 950 of these employees at December 31, 2013.

(d) Financial Information about Geographical Areas

We have no significant amount 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.



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.

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 business 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 more favorable investment opportunities may cause the trading price of our units to decline.

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 condition that results in lower purchases of refined petroleum products;


•	higher refined products prices due to an increase in the market price of crude oil, changes in economic conditions, or other factors;


•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products;


•	a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and


•	a temporary or permanent material increase in the price of refined products as compared to alternative sources of refined products available to our customers.

A material decrease in demand or distribution of crude oil available for transport through our pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.

The volume of crude oil transported through our crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by our assets. A period of sustained crude oil price declines 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 these areas. In either case, the volumes of crude oil transported in our crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil 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.

Any reduction in throughput capacity available to our shippers, including our crude oil and refined products acquisition and marketing businesses, on either our pipelines or interconnecting third-party pipelines could cause a reduction of volumes transported in our pipelines and through 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 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 in our pipelines or through 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 in our pipelines or through 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 and refined products acquisition and marketing businesses are dependent upon our 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.

A material decrease in demand for natural gas liquids ("NGLs") in the markets served by our assets 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 in our pipelines or through our terminals. 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 or 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.

If we are unable to complete capital projects at their expected costs and/or in a timely manner, 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. 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 and refined products and overall customer demand.

An impairment of goodwill and intangible assets could reduce our earnings.

At December 31, 2013, our consolidated balance sheet reflected $1.35 billion of goodwill and $794 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 charge to earnings with a correlative effect on partners' capital and balance sheet leverage as measured by debt to total capitalization.

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 crude oil marketing margins 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.

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 is to be in effect through July 2016. If the changes in the index 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 refined products and crude oil result in a risk that refined products, crude oil, 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 refined products and crude oil 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 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 and 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 services licenses and which 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 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.

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.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. While the primary measures used by management to evaluate past performance and future prospects exclude any impacts attributable to unsettled hedges, our consolidated financial statements may reflect some volatility due to the recognition of changes in fair value of these hedges in periods other than those in which the related physical transaction occurs. See Part II., Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional information on the measure described above.

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 third-party service providers. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.

We utilize both affiliate 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.

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, 2013, approximately 47 percent of our workforce was covered by a number of collective bargaining agreements with various terms and dates of expirations. 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.

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 to 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.

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.

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 two percent general partner interest and owns 32.2 percent of our limited partnership interests. 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. 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 32.2 percent of our limited partnership interests 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.

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.

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, 2013, our total outstanding indebtedness was $2.38 billion excluding net unamortized fair value adjustments. 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 our 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.

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, as applicable, reserves or the reserves of our or Sunoco Logistics Partners L.P.'s, as applicable, operating subsidiaries 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, 2013, we had $235 million 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 down-grading in ETP's credit ratings could also result in a down-grading 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.

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. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may impact adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

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. Treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders. Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or to otherwise subject us to a material level of entity-level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to unitholders would be reduced. The 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 a material level of entity-level taxation for federal, state, or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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 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 includable 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 limited partner units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those limited partner 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 limited partner unit is sold at a price greater than their tax basis in that limited partner 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.

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 more than 30 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. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, members of Congress have been considering substantive changes to the definition of qualifying income and the treatment of certain types of income earned from partnerships. While these specific proposals would not appear to affect our treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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.



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 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 refined 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 of 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. The Partnership has not received any proposed penalties associated with this release and continues to cooperate with both PHMSA and the EPA to complete the investigation of the incident and repair of the pipeline.

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 U.S. Department of Justice ("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 and hopes to resolve the issue during 2014.

The Partnership's Sunoco Pipeline L.P. subsidiary ("Sunoco Pipeline") operates the West Texas Gulf Pipeline on behalf of West Texas Gulf Pipe Line Company and its shareholders, pursuant to an Operating Agreement. Sunoco Pipeline also has as 60.3 percent ownership interest in the company. In March 2010, Sunoco Pipeline received a Notice of Probable Violation, Proposed Civil Penalty and proposed Compliance Order from PHMSA with proposed civil penalties in connection with a crude oil release that occurred at the Colorado City, Texas station on the West Texas Gulf Pipeline in June 2009. PHMSA issued a final order in August 2012, finding the Partnership in violation of all items identified in the original notice. The Partnership paid $0.4 million during the third quarter 2012, but requested a petition for reconsideration on certain of the violations. A settlement on the remaining violations was reached and the Partnership paid less than $0.1 million during the first quarter 2013.

In September 2013, the Pennsylvania Department of Environmental Protection ("PADEP") issued a Notice of Violation and proposed penalties in excess of $0.1 million based on alleged violations of various safety regulations relating to the November 2008 products release by Sunoco Pipeline in Murrysville, Pennsylvania. The Partnership is currently in discussions with the PADEP. 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.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.

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 26, 2014, there were 72 holders of record of our common units. These holders of record included the general partner with 33.5 million common units registered in its name, and Cede & Co., a clearing house for stock transactions, with the majority of the remaining 70.5 million common units registered to it.

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 general partner's limited partnership units, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities offered by our general partner in that offering.

The high and low sales price ranges (composite transactions) and distributions declared (per unit) by quarter for 2013 and 2012 were as follows:



	2013						2012
	Unit Price				Declared Distributions		Unit Price				Declared Distributions
Quarter	High		Low		Declared Distributions		High		Low		Declared Distributions
1^st	$	68.44	$	50.33	$	0.5725	$	42.11	$	35.01	$	0.4275
2^nd	$	65.76	$	57.75	$	0.6000	$	40.99	$	31.65	$	0.4700
3^rd	$	68.21	$	58.59	$	0.6300	$	50.40	$	36.29	$	0.5175
4^th	$	76.07	$	64.81	$	0.6625	$	52.04	$	44.00	$	0.5450

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 $0.15 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.

If cash distributions exceed $0.1667 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").

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
	Total Quarterly Distribution Target Amount	General Partner			Unitholders
Minimum Quarterly Distribution	$0.1500	2	%		98%
First Target Distribution	up to $0.1667	2	%		98%
	above $0.1667
Second Target Distribution	up to $0.1917	15	%	⁽¹⁾	85%
	above $0.1917
Third Target Distribution	up to $0.5275	37	%	⁽¹⁾	63%
Thereafter	above $0.5275	50	%	⁽¹⁾	50%



⁽¹⁾	Includes two percent general partner interest.



ITEM 6.	SELECTED FINANCIAL DATA

The following tables present selected current and historical audited 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."



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	Year Ended December 31, 2013						Period from January 1, 2012 to October 4, 2012			2011			2010			2009
	(in millions, except per unit data)						(in millions, except per unit data)
Income Statement Data:
Revenues:
Sales and other operating revenue:
Unaffiliated customers	$	15,073		$	2,989		$	9,460		$	10,473		$	6,691		$	4,696
Affiliates	1,566			200			461			432			1,117			706
Gain on divestment and related matters	—			—			11			—			—			—
Total revenues	$	16,639		$	3,189		$	9,932		$	10,905		$	7,808		$	5,402
Operating income ⁽¹⁾	$	560		$	159		$	460		$	423		$	271		$	267
Other income ⁽²⁾	$	21		$	5		$	18		$	13		$	30		$	28
Income before income tax expense	$	504		$	150		$	413		$	347		$	356		$	250
Net Income	$	474		$	142		$	389		$	322		$	348		$	250
Net Income attributable to noncontrolling interests	(11		)	(3		)	(8		)	(9		)	(2		)	—
Net Income attributable to Sunoco Logistics Partners L.P.	$	463		$	139		$	381		$	313		$	346		$	250
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit: ⁽³⁾
Basic	$	3.27		$	1.11		$	3.15		$	2.56		$	3.13		$	2.17
Diluted	$	3.25		$	1.10		$	3.14		$	2.54		$	3.11		$	2.16
Cash distributions per unit to Limited Partners: ^{(3) (4)}
Paid	$	2.35		$	0.52		$	1.32		$	1.61		$	1.51		$	1.37
Declared	$	2.47		$	0.55		$	1.42		$	1.64		$	1.54		$	1.40
Other Data:
Adjusted EBITDA ⁽⁵⁾	$	871		$	219		$	591		$	573		$	399		$	372
Distributable Cash Flow ⁽⁵⁾	$	655		$	165		$	439		$	390		$	242		$	264

⁽¹⁾

During the first quarter 2013, we adjusted our presentation of operating income reported in the consolidated statements of comprehensive income to conform to the presentation utilized by Energy Transfer Partners, L.P., the controlling member of our general partner. Other income, which is comprised primarily of equity income from our unconsolidated joint-venture interests, is presented separately and is no longer included as a component of operating income. These changes did not impact our net income. Prior period amounts have been recast to conform to current presentation.

⁽²⁾

Includes equity income from our investments in the following joint ventures: Explorer Pipeline Company, Wolverine Pipe Line Company, West Shore Pipe Line Company ("West Shore"), Yellowstone Pipe Line Company, Mid-Valley Pipeline Company ("Mid-Valley") and West Texas Gulf Pipe Line Company ("West Texas Gulf"). Equity income from the investments has been included based on our respective ownership percentages of each, and from the dates of acquisition forward. In the third quarter 2010, we acquired a controlling financial interest in Mid-Valley and West Texas Gulf. Therefore, these joint ventures are reflected as consolidated subsidiaries from the respective dates of acquisition.


⁽³⁾	On December 2, 2011, we completed a three-for-one split of our common and Class A units. The unit split resulted in the issuance of two additional common or Class A units for every one unit owned. All unit and per unit information is presented on a post-split basis.


⁽⁴⁾	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.

⁽⁵⁾

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, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	Year Ended December 31, 2013						Period from January 1, 2012 to October 4, 2012			2011			2010			2009
	(in millions)						(in millions)
Net Income	$	474		$	142		$	389		$	322		$	348		$	250
Interest expense, net	77			14			65			89			73			45
Depreciation and amortization expense	265			63			76			86			64			48
Impairment charge	—			—			9			31			3			—
Provision for income taxes	30			8			24			25			8			—
Non-cash compensation expense	14			2			6			6			5			5
Unrealized losses/(gains) on commodity risk management activities	(1		)	(3		)	6			(2		)	2			—
Amortization of excess equity method investment	2			—			—			—			—			—
Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes	20			5			16			16			24			24
Non-cash accrued liability adjustment	(10		)	—			—			—			—			—
Adjustments to commodity hedges resulting from "push-down" accounting	—			(12		)	—			—			—			—
Gain on investments in affiliates	—			—			—			—			(128		)	—
Adjusted EBITDA	871			219			591			573			399			372
Interest expense, net	(77		)	(14		)	(65		)	(89		)	(73		)	(45		)
Provision for income taxes	(30		)	(8		)	(24		)	(25		)	(8		)	—
Amortization of fair value adjustments on long-term debt	(23		)	(6		)	—			—			—			—
Distributions versus Adjusted EBITDA of unconsolidated affiliates	(27		)	(3		)	(25		)	(17		)	(36		)	(31		)
Maintenance capital expenditures	(53		)	(21		)	(29		)	(42		)	(37		)	(32		)
Distributable Cash Flow attributable to noncontrolling interests	(15		)	(2		)	(9		)	(10		)	(3		)	—
Contributions attributable to acquisition from affiliate	9			—			—			—			—			—
Distributable Cash Flow	$	655		$	165		$	439		$	390		$	242		$	264



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	Year Ended December 31, 2013						Period from January 1, 2012 to October 4, 2012			2011			2010			2009
	(in millions)						(in millions)
Net cash provided by operating activities	$	749		$	280		$	411		$	430		$	341		$	176
Interest expense, net	77			14			65			89			73			45
Amortization of bond premium, financing fees and bond discount	22			6			(2		)	(2		)	(2		)	(2		)
Deferred income tax (expense) benefit	(6		)	2			—			2			—			—
Regulatory matters excluded from Adjusted EBITDA	—			—			10			(11		)	—			—
Claim for (recovery of) environmental liability	—			(13		)	14			—			—			—
Expected proceeds from insurance recovery	1			—			—			—			—			—
Net change in working capital pertaining to operating activities	(21		)	(94		)	35			35			(55		)	121
Unrealized losses/(gains) on commodity risk management activities	(1		)	(3		)	6			(2		)	2			—
Amortization of excess equity method investment	2			—			—			—			—			—
Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes	20			5			16			16			24			24
Non-cash accrued liability adjustment	(10		)	—			—			—			—			—
Adjustments to commodity hedges resulting from "push-down" accounting	—			(12		)	—			—			—			—
Provision for income taxes	30			8			24			25			8			—
Other	8			26			12			(9		)	8			8
Adjusted EBITDA	$	871		$	219		$	591		$	573		$	399		$	372

Our management believes Adjusted EBITDA and distributable cash flow information enhances an investor's understanding of a business's ability to generate cash for payment of distributions and other purposes. In addition, Adjusted EBITDA is also used as a measure in determining our compliance with certain revolving credit facility covenants. 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.



	Successor						Predecessor
	Year Ended December 31, 2013 ⁽¹⁾			Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽²⁾			Period from January 1, 2012 to October 4, 2012 ⁽²⁾			Year Ended December 31,
	Year Ended December 31, 2013 ⁽¹⁾						Period from January 1, 2012 to October 4, 2012 ⁽²⁾			2011 ⁽³⁾			2010 ⁽⁴⁾			2009 ⁽⁵⁾
	(in millions)						(in millions)
Cash Flow Data:
Net cash provided by operating activities	$	749		$	280		$	411		$	430		$	341		$	176
Net cash used in investing activities	$	(957	)	$	(139	)	$	(224	)	$	(609	)	$	(426	)	$	(226	)
Net cash provided by (used in) financing activities	$	244		$	(140	)	$	(190	)	$	182		$	85		$	50
Capital expenditures:
Expansion ⁽⁶⁾	$	851		$	118		$	206		$	171		$	137		$	144
Maintenance ⁽⁷⁾	46			21			29			42			37			32
Major acquisitions	60			—			—			396			252			50
Total capital expenditures	$	957		$	139		$	235		$	609		$	426		$	226

⁽¹⁾

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 refined products acquisition and marketing services; 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 Facility from Sunoco for $60 million in 2013.

⁽²⁾

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 refined products acquisition and marketing services, 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.

⁽³⁾

Expansion capital expenditures in 2011 included projects to expand upon our butane blending services, increase tankage at the Nederland facility, increase connectivity of the crude oil pipeline assets in Texas and increase our crude oil trucking fleet to meet the demand for transportation services in the southwest United States. Cash flows related to major acquisitions in 2011 included $73 million related to the acquisition of the East Boston terminal, $222 million related to the acquisition of the Texon L.P. ("Texon") crude oil purchasing and marketing business, $2 million related to the acquisition of the Eagle Point tank farm and $99 million related to the acquisition of a controlling financial interest in Inland Corporation ("Inland").

⁽⁴⁾

Expansion capital expenditures in 2010 included construction projects to expand services at our refined products terminals, increase tankage at the Nederland Terminal and to expand upon our refined products platform in the southwest United States. Cash flows related to major acquisitions in 2010 included $152 million related to the acquisition of a butane blending business from Texon, $91 million related to the acquisition of additional ownership interests in Mid-Valley, West Texas Gulf and West Shore and $9 million for the acquisition of two terminals in Texas.

⁽⁵⁾

Expansion capital expenditures in 2009 included the construction of tankage and pipeline assets in connection with our agreement to connect the Nederland Terminal to a Port Arthur, Texas refinery and construction of additional crude oil storage tanks at the Nederland Terminal. Cash flows related to major acquisitions in 2009 included $50 million related to the acquisition of Excel Pipeline LLC and a refined products terminal in Romulus, Michigan.


⁽⁶⁾	Expansion capital expenditures are capital expenditures made to acquire and integrate complimentary 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.


⁽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.



	Successor				Predecessor
	December 31,				December 31,
	2013		2012		2011		2010		2009
	(in millions)				(in millions)
Balance Sheet Data (at period end):
Net properties, plants and equipment	$	6,519	$	5,623	$	2,522	$	2,128	$	1,534
Total assets	$	11,897	$	10,361	$	5,477	$	4,188	$	3,099
Total debt	$	2,503	$	1,732	$	1,698	$	1,229	$	868
Total Sunoco Logistics Partners L.P. Equity	$	6,204	$	6,072	$	1,096	$	965	$	862
Noncontrolling interests	121		123		98		77		—
Total equity	$	6,325	$	6,195	$	1,194	$	1,042	$	862



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012		Period from January 1, 2012 to October 4, 2012		Year Ended December 31,
							2011		2010		2009
Operating Data:
Crude Oil Pipelines ⁽¹⁾
Pipeline throughput (thousands of barrels per day ("bpd")) ⁽²⁾	1,866		1,584		1,546		1,587		1,183		658
Pipeline revenue per barrel (cents)	72.7		75.6		68.0		55.0		50.7		77.5
Crude Oil Acquisition and Marketing ⁽³⁾
Crude oil purchases (thousands of bpd)	749		669		674		663		638		592
Gross profit per barrel purchased (cents)⁽⁴⁾	91.4		138.0		92.8		66.0		21.0		25.0
Average crude oil price (per barrel)	$	98.00	$	88.20	$	96.20	$	95.14	$	79.55	$	61.93
Terminal Facilities ⁽⁵⁾
Terminal throughput (thousands of bpd)
Refined products terminals	431		451		499		492		488		462
Nederland terminal	932		787		703		757		729		597
Refinery terminals	397		411		369		443		465		591
Refined Products Pipelines ⁽¹⁾
Pipeline throughput (thousands of bpd) ⁽⁶⁾	571		601		565		522		468		577
Pipeline revenue per barrel (cents)	62.5		63.0		62.2		68.3		70.0		60.7


⁽¹⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

⁽²⁾

In July and August 2010, we acquired controlling financial interests in Mid-Valley and West Texas Gulf, respectively, and we accounted for the entities as consolidated subsidiaries from the dates of their respective acquisitions. Average volumes for the year ended December 31, 2010 of 278 thousand bpd have been included in the consolidated total. From the dates of acquisition, these pipelines had actual throughput of 696 thousand bpd for the year ended December 31, 2010.


⁽³⁾	Includes results from the crude oil acquisition and marketing business acquired from Texon in August 2011 from the acquisition date.


⁽⁴⁾	Represents total segment sales and other operating revenue minus cost of products sold and operating expenses divided by crude oil purchases.


⁽⁵⁾	In July 2011 and August 2011, we acquired the Eagle Point tank farm and a refined products terminal located in East Boston, Massachusetts, respectively. Volumes and revenues for these acquisitions are included from their acquisition dates.

⁽⁶⁾



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 is principally engaged in the transport, terminalling and storage of crude oil, refined products and natural gas liquids ("NGLs"). In addition to logistics services, we also own acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products and NGLs. Our portfolio of geographically diverse assets earns revenues in more than 30 states located throughout the United States. Revenues are generated by charging tariffs for transporting crude oil, refined products and NGLs 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, refined products and NGLs. 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.

On October 5, 2012, Sunoco, Inc. ("Sunoco") was acquired by Energy Transfer Partners, L.P. ("ETP"). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as our general partner and owned a two percent general partner interest, all of our incentive distribution rights and a 32.4 percent limited partner interest in SXL. In connection with the acquisition, Sunoco’s general and limited partner interests in us were contributed to ETP, resulting in a change in control of our general partner. As a result, we became a consolidated subsidiary of ETP and elected to apply "push-down" accounting, which required our assets and liabilities to be adjusted to fair value on the closing date, October 5, 2012. The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. Due to the application of "push-down" accounting, our consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting during those periods. The periods prior to the acquisition date, October 5, 2012, are identified as "Predecessor" and the periods from October 5, 2012 forward are identified as "Successor," and our operating results for the years ended December 31, 2013, 2012 and 2011 are presented in comparative periods. We performed an analysis and determined that the activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows. Therefore, operating results between October 1, 2012 and October 4, 2012 have been included within the "Successor" period ended December 31, 2012.

In July 2013, the limited liability agreement of Sunoco Partners LLC was amended to reflect the addition of ETE Common Holdings, LLC ("ETE Holdings") as an owner of a 0.1 percent membership interest in our general partner. ETE Holdings is a wholly-owned subsidiary of Energy Transfer Equity, L.P., and an affiliate of ETP. This change in the ownership of the general partner did not impact our consolidated financial statements. Subsequent to the amendment, we remain a consolidated subsidiary of ETP. In addition, the 33.5 million common units owned by Sunoco Partners LLC were assigned to ETP.

Strategic Actions

Our primary business strategies focus on generating stable cash flows by increasing pipeline and terminal throughput, utilizing our crude oil gathering assets to maximize value for producers, pursuing economically accretive organic growth opportunities, and continuing to improve operating 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.

Acquisitions

Since December 31, 2010, we completed five acquisitions for a total of $554 million.

2013 Acquisition

•

Marcus Hook Facility—In the second quarter 2013, we acquired Sunoco's Marcus Hook facility and related assets (the "Marcus Hook Facility"). The acquisition of terminalling and storage assets located in Pennsylvania and Delaware included underground storage caverns with a capacity of approximately 2 million barrels, deep water berths, rail access and trucking capabilities, and advantageous pipeline access. In addition, the acquisition included commercial agreements, including a reimbursement agreement under which Sunoco will reimburse us

$40 million for certain operating expenses of the Marcus Hook Facility through March 31, 2017. Since the transaction was with an entity under common control, we recorded the assets acquired and liabilities assumed at Sunoco's net carrying value. The acquisition was included within the Terminal Facilities segment.

2011 Acquisitions

•

East Boston Terminal—In August 2011, we acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips. The terminal is the sole service provider to Logan International Airport under a long-term contract to supply jet fuel. The terminal includes a 10-bay truck rack and approximately 1 million barrels of capacity. The terminal was included in the Terminal Facilities segment from the date of acquisition;

•

Crude Oil Acquisition and Marketing Business—In August 2011, we acquired a crude oil acquisition and marketing business from Texon L.P. ("Texon"). The purchase consisted of a lease crude business and gathering assets in 16 states, primarily in the western United States. The crude oil volume of the business consisted of approximately 75,000 barrels per day at the wellhead. The business was included in the Crude Oil Acquisition and Marketing segment from the date of acquisition;


•	Eagle Point Tank Farm—In July 2011, we acquired the Eagle Point tank farm from Sunoco. The tank farm is located in Westville, New Jersey and consists of approximately 5 million barrels of active storage for refined products and dark oils. The tank farm was included in the Terminal Facilities segment from the date of acquisition; and,

•

Controlling Financial Interest in Inland Corporation—In May 2011, we acquired an 83.8 percent equity interest in Inland Corporation ("Inland"), which is the owner of 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets in Ohio. We acquired our equity interest through a purchase of a 27.0 percent equity interest from Shell Oil Company and a 56.8 percent equity interest from Sunoco. The pipeline was included in the Refined Products Pipeline segment from the date of acquisition.

Growth Capital Program

In 2013, we invested $965 million in organic growth capital projects to improve operational efficiencies, reduce costs, expand existing facilities and construct new assets to increase storage, throughput volume or the scope of services we are able to provide. These included projects to: invest in our crude oil infrastructure by increasing pipeline capabilities through previously announced expansion capital projects in Texas and Oklahoma; expand upon refined products acquisition and marketing services; upgrade the service capabilities at the Eagle Point and Nederland terminals; and invest in the previously announced Mariner and Allegheny Access projects. We continued to expand our operations into pipeline transportation, storage and acquisition and marketing of NGLs in the northeastern United States with the successful launch of our pipeline project to deliver ethane from the Marcellus Shale Basin to Ontario ("Project Mariner West") and the acquisition of the Marcus Hook Facility. The results of the NGL pipeline transportation operations are included in the Refined Products Pipelines segment and the results of the NGL acquisition, storage and marketing activities are included in the Terminal Facilities segment. While these activities have not had a material impact on our operational results to date, we will continue to expand our NGL platform through previously announced growth projects that are expected to commence operations throughout 2014 and 2015.

During 2014, we expect to invest at least $1.3 billion in expansion capital expenditures related to organic growth, excluding major acquisitions. This includes spending to capture more value from existing assets such as the Marcus Hook Facility, the Nederland Terminal and our patented blending technology. Expansion capital expenditures in 2014 will also include continued progress on our previously announced growth projects:

Allegheny Access

In 2012, we completed a successful Open Season for our project to transport refined products from the midwest to eastern Ohio and western Pennsylvania markets. This project will utilize new and existing assets and is expected to transport 85,000 barrels per day, with the possibility for expansion to meet further demand. The project is expected to commence operations during the third quarter 2014.

Eaglebine Express

In the second quarter 2013, we completed a successful Open Season for our Eaglebine Express pipeline. An existing portion of our MagTex refined products pipeline will be converted into crude service and its flow reversed, to provide takeaway capacity for the growing production in the Eaglebine and Woodbine crude areas. Eaglebine Express is expected to transport approximately 60,000 barrels per day from Hearne, Texas to Nederland, Texas starting in the third quarter 2014.

Granite Wash Extension

In the third quarter 2013, we completed a successful Open Season for our Granite Wash Extension pipeline. The pipeline is expected to provide 70,000 barrels per day of crude oil takeaway capacity for the growing production from the Granite Wash Shale in the northeastern Texas panhandle and portions of western Oklahoma. We will construct approximately 200 miles of new pipeline, originating in Wheeler County, Texas and terminating in Ringgold, Texas, and new pump stations and truck unloading facilities. At Ringgold, the new pipeline will connect with our existing pipelines, which have the ability to transport to Corsicana, Texas. From Corsicana, access to multiple SXL and third-party pipelines will provide producers the ability to reach various markets and refineries on the Gulf Coast and in the MidContinent. The pipeline is expected to be operational in the third quarter 2014.

Permian Express 2

In the fourth quarter 2013, we completed a successful Open Season for our Permian Express 2 pipeline. The Permian Express 2 pipeline project involves the construction of approximately 300 to 400 miles of new crude oil pipelines, with origins in multiple locations in West Texas: Midland, Garden City and Colorado City. With an expected initial capacity of approximately 200,000 barrels per day, Permian Express 2 is expected to deliver to multiple refiners and markets beginning in the second quarter 2015.

Mariner East

In September 2012, we announced a successful Open Season for our project to deliver NGLs produced in the Marcellus Shale Basin to the Marcus Hook Facility ("Project Mariner East 1"). This pipeline and marine terminal project will allow us to transport NGLs, primarily utilizing modified existing pipelines, from western Pennsylvania to the east coast where approximately 2 million barrels of NGLs can be stored in our underground caverns and loaded on waterborne vessels for third-party transport to other United States ports or exported to international markets. The project is expected to support the transportation of approximately 70,000 barrels per day. The transportation of propane is expected to commence in the second half of 2014, with the transportation of ethane expected to commence in mid-2015. As a result of substantial interest expressed by producers, marketers and industrial consumers for long-term transportation of Marcellus and Utica Shale NGLs to the Marcus Hook Facility, we launched an Open Season for Project Mariner East 2 during the fourth quarter 2013.

Mariner South

In May 2013, we announced that sufficient binding commitments had been received to move forward on our joint project with Lone Star NGL LLC ("Lone Star"). This Mariner South Pipeline will transport export-grade propane and butane from Lone Star's Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas. The pipeline is expected to have an initial capacity of approximately 200,000 barrels per day and can be scaled to support higher volumes as needed. In addition to export-grade propane and butane, the pipeline will be available to transport other NGLs and petroleum products depending on shipper interest. The pipeline is expected to be operational in the first quarter 2015.

Conservative Capital Structure

Our goal is to maintain substantial liquidity and a conservative capital structure. In 2013, Sunoco Logistics Partners Operations L.P. (the "Operating Partnership"), our wholly-owned subsidiary, increased our borrowing capacity by entering into a five-year $1.50 billion unsecured credit facility (the "$1.50 billion Credit Facility"). The $1.50 billion Credit Facility contains an "accordion" feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions. 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, 2013. For the quarter ended December 31, 2013, the distribution increased to $0.6625 per common unit ($2.65 annualized). The distribution for the fourth quarter 2013 was paid on February 14, 2014.

Results of Operations



	Successor									Predecessor
	Three Months Ended December 31, 2013			Nine Months Ended September 30, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾			Period from January 1, 2012 to October 4, 2012 ⁽¹⁾			Three Months Ended December 31, 2011			Nine Months Ended September 30, 2011
	(in millions, except per unit data)									(in millions, except per unit data)
Statements of Income
Sales and other operating revenue:
Unaffiliated customers	$	3,907		$	11,166		$	2,989		$	9,460		$	3,325		$	7,148
Affiliates	381			1,185			200			461			51			381
Gain on divestment and related matters	—			—			—			11			—			—
Total revenues	4,288			12,351			3,189			9,932			3,376			7,529
Cost of products sold	4,040			11,534			2,885			9,214			3,144			7,009
Operating expenses	30			87			48			97			34			77
Selling, general and administrative expenses	23			100			34			86			23			67
Depreciation and amortization expense	69			196			63			76			25			61
Impairment charge and related matters ⁽²⁾	—			—			—			(1		)	42			—
Total costs and expenses	4,162			11,917			3,030			9,472			3,268			7,214
Operating income ⁽³⁾	126			434			159			460			108			315
Net interest expense	(19		)	(58		)	(14		)	(65		)	(26		)	(63		)
Other income	5			16			5			18			4			9
Income before provision for income taxes	112			392			150			413			86			261
Provision for income taxes	(7		)	(23		)	(8		)	(24		)	(7		)	(18		)
Net Income	105			369			142			389			79			243
Net Income attributable to noncontrolling interests	(3		)	(8		)	(3		)	(8		)	(3		)	(6		)
Net Income attributable to Sunoco Logistics Partners L.P.	$	102		$	361		$	139		$	381		$	76		$	237
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit:
Basic	$	0.64		$	2.63		$	1.11		$	3.15		$	0.60		$	1.96
Diluted	$	0.63		$	2.62		$	1.10		$	3.14		$	0.60		$	1.95


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.

⁽²⁾

We recognized a $42 million charge in the fourth quarter 2011 for certain crude oil terminal assets which would have been negatively impacted in connection with Sunoco's exit from the refining business. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations. In September 2012, Sunoco contributed the refining assets of its Philadelphia refinery to Philadelphia Energy Solutions ("PES"), a joint venture between The Carlyle Group and Sunoco, which enabled the Philadelphia refinery to continue operating. As a result, we reversed $10 million of regulatory obligations during 2012 which were no longer expected to be incurred.

⁽³⁾

During the first quarter 2013, we adjusted our presentation of operating income to conform to the presentation utilized by ETP. Other income, which is comprised primarily of equity income from our unconsolidated joint-venture interests, is presented separately and is no longer included as a component of operating income. These changes did not impact our net income. Prior period amounts have been recast to conform to current presentation.

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 Adjusted EBITDA and DCF information enhances an investor's understanding of a business's 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.

During the fourth quarter 2012, we changed our definition of Adjusted EBITDA and DCF to conform to the presentation utilized by our general partner. During the first quarter 2013, we also changed our measure of segment profit from operating income to the revised presentation of Adjusted EBITDA. This change did not impact our reportable segments. Prior period amounts have been recast to conform to current presentation.

The following table reconciles the differences between net income, as determined under GAAP, and Adjusted EBITDA and DCF.



	Successor									Predecessor
	Three Months Ended December 31, 2013			Nine Months Ended September 30, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾			Period from January 1, 2012 to October 4, 2012 ⁽¹⁾			Three Months Ended December 31, 2011			Nine Months Ended September 30, 2011
	(in millions)									(in millions)
Net Income	$	105		$	369		$	142		$	389		$	79		$	243
Interest expense, net	19			58			14			65			26			63
Depreciation and amortization expense	69			196			63			76			25			61
Impairment charge	—			—			—			9			31			—
Provision for income taxes	7			23			8			24			7			18
Non-cash compensation expense	4			10			2			6			1			5
Unrealized losses/(gains) on commodity risk management activities	11			(12		)	(3		)	6			6			(8		)
Amortization of excess equity method investment	1			1			—			—			—			—
Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes	4			16			5			16			4			12
Non-cash accrued liability adjustment	(10		)	—			—			—			—			—
Adjustments to commodity hedges resulting from "push-down" accounting	—			—			(12		)	—			—			—
Adjusted EBITDA	210			661			219			591			179			394
Interest expense, net	(19		)	(58		)	(14		)	(65		)	(26		)	(63		)
Provision for income taxes	(7		)	(23		)	(8		)	(24		)	(7		)	(18		)
Amortization of fair value adjustments on long-term debt	(6		)	(17		)	(6		)	—			—			—
Distributions versus Adjusted EBITDA of unconsolidated affiliates	(6		)	(21		)	(3		)	(25		)	(4		)	(13		)
Maintenance capital expenditures	(16		)	(37		)	(21		)	(29		)	(22		)	(20		)
Distributable Cash Flow attributable to noncontrolling interests	(4		)	(11		)	(2		)	(9		)	(2		)	(8		)
Contributions attributable to acquisition from affiliate	3			6			—			—			—			—
Distributable Cash Flow	$	155		$	500		$	165		$	439		$	118		$	272


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.

Analysis of Consolidated Operating Results

Net income attributable to Sunoco Logistics Partners L.P. ("net income attributable to SXL") was $102 and $139 million for the fourth quarter 2013 and the period from October 5, 2012 to December 31, 2012, respectively. The $37 million decrease was driven by decreased operating performance from the Crude Oil Acquisition and Marketing and Refined Products Pipelines segments, increased depreciation expense and the absence of $12 million of adjustments on commodity hedges that were recognized in connection with push-down accounting. These decreases were partially offset by improved operating

performance in the Crude Oil Pipelines segment and decreased selling, general and administrative expenses primarily attributable to a non-cash accrued liability adjustment. Net interest expense increased due largely to the $700 million Senior Notes offering in January 2013 and was partially offset by increased capitalized interest associated with our expansion capital program.

Net income attributable to SXL was $361 and $381 million for the nine months ended September 30, 2013 and the period from January 1, 2012 to October 4, 2012, respectively. Results for 2012 included $25 million of non-recurring gains recognized in connection with the sale of the Big Sandy terminal and pipelines assets, the reversal of regulatory obligations that were recorded in 2011 and an asset sale by one of our joint-venture interests. Excluding these items, net income attributable to SXL increased $5 million compared to the prior period. Improved operating performance from the Crude Oil Pipelines and Crude Oil Acquisition and Marketing segments was largely offset by higher depreciation and amortization expense attributable to the acquisition of our general partner by ETP; higher selling, general and administrative expenses and decreased operating performance from the Refined Products Pipelines segment. The decrease in net interest expense was primarily related to increased capitalized interest associated with our expansion capital program. Additional interest expense related to the $700 million Senior Notes offering in January 2013 was largely offset by non-cash amortization related to fair value adjustments on our long-term debt.

Net income attributable to SXL was $139 million for the period from October 5, 2012 to December 31, 2012 compared to $76 million for the fourth quarter 2011. The $63 million increase was the result of improved operating performance which benefited from strong demand for crude oil transportation services and the absence of $42 million of impairment and related charges recognized in the fourth quarter 2011. Partially offsetting these positive factors were additional depreciation and amortization expense attributable to our assets being adjusted to fair value in connection with the acquisition of the general partner by ETP and higher selling, general and administrative expenses attributable to increased employee costs and contract services associated with growth in the business.

Net income attributable to SXL was $381 million for the period from January 1, 2012 to October 4, 2012 compared to $237 million for the nine months ended September 30, 2011. The $144 million increase in 2012 was due primarily to improved operating performance which benefited from strong demand for crude oil transportation services and contributions from our 2011 acquisitions and organic projects. Included in current year results were gains of $25 million due to the reversal of regulatory obligations that were recorded in 2011, a contract settlement in connection with the sale of a refined products terminal and pipeline assets and an asset sale by one of our joint venture interests. These positive factors were partially offset by increased interest expense related primarily to the $600 million Senior Notes offering in July 2011 and higher selling, general and administrative expenses attributable to increased employee costs, incentive compensation and contract services associated with growth in the business.

Analysis of Operating Segments

We manage our operations through four operating segments: Crude Oil Pipelines, Crude Oil Acquisition and Marketing, Terminal Facilities and Refined Products Pipelines.

Crude Oil Pipelines

Our Crude Oil Pipelines segment consists of crude oil trunk and gathering pipelines in the southwest and midwest United States, including those owned by our joint-venture interests. Revenues are generated from tariffs and the associated fees paid by shippers utilizing our transportation services to deliver crude oil and other feedstocks to refineries within those regions. Rates for shipments on these pipelines are regulated by the Federal Energy Commission ("FERC"), Oklahoma Corporation Commission ("OCC") and the Railroad Commission of Texas ("Texas R.R.C.").

The following table presents the operating results and key operating measures for our Crude Oil Pipelines segment for the periods presented:



	Successor						Predecessor
	Three Months Ended December 31, 2013		Nine Months Ended September 30, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾		Period from January 1, 2012 to October 4, 2012 ⁽¹⁾		Three Months Ended December 31, 2011		Nine Months Ended September 30, 2011
	(in millions, except for barrel amounts)						(in millions, except for barrel amounts)
Sales and other operating revenue
Unaffiliated customers	$	85	$	210	$	70	$	187	$	55	$	141
Affiliates	—		—		—		—		—		6
Intersegment revenue	54		146		40		101		31		86
Total sales and other operating revenue	$	139	$	356	$	110	$	288	$	86	$	233
Depreciation and amortization expense	$	23	$	67	$	22	$	19	$	6	$	19
Adjusted EBITDA	$	102	$	247	$	72	$	203	$	58	$	149
Pipeline throughput (thousands of barrels per day ("bpd"))	2,009		1,817		1,584		1,546		1,577		1,591
Pipeline revenue per barrel (cents)	75.2		71.7		75.6		68.0		58.9		53.7


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.

Adjusted EBITDA for the Crude Oil Pipelines segment for the fourth quarter 2013 increased $30 million compared to the period from October 5, 2012 to December 31, 2012. This increase was due primarily to higher throughput volumes ($30 million) largely attributable to expansion projects which began operating during 2013 and strong demand for West Texas crude oil. Results also benefited from lower maintenance and integrity management costs ($2 million) which were offset by increased utility costs associated with higher throughput volumes and lower pipeline operating gains ($2 million).

Adjusted EBITDA for the Crude Oil Pipelines segment increased $44 million to $247 million for the nine months ended September 30, 2013, compared to $203 million for the period from January 1, 2012 to October 4, 2012. The increase in Adjusted EBITDA was due primarily to higher throughput volumes ($49 million) largely attributable to our pipeline expansion projects in Texas and Oklahoma and higher pipeline tariffs ($19 million). These improvements were partially offset by higher operating expenses ($24 million) driven primarily by lower pipeline operating gains, increased environmental remediation expenses, higher utility costs associated with higher throughput volumes and increased maintenance costs.

Adjusted EBITDA for the Crude Oil Pipelines segment for the period from October 5, 2012 to December 31, 2012 increased $14 million compared to the prior year period due primarily to higher pipeline tariffs which were the result of organic projects placed into service during 2012 and an improved mix of higher tariff movements driven by strong demand for West Texas crude oil ($24 million). These improvements were partially offset by lower pipeline operating gains ($3 million), higher maintenance and integrity management costs ($3 million) and increased selling, general and administrative expenses ($3 million).

Adjusted EBITDA for the Crude Oil Pipelines segment increased $54 million to $203 million for the period from January 1, 2012 to October 4, 2012, as compared to $149 million for the nine months ended September 30, 2011. The increase in Adjusted EBITDA was driven primarily by higher pipeline fees which benefited from tariff increases relative to the prior year period, organic growth projects and an improved mix of pipeline movements which benefited from the demand for West Texas crude oil ($61 million). Partially offsetting these improvements were increased selling, general and administrative expenses ($7 million) and overall volume reductions ($6 million).

Crude Oil Acquisition and Marketing

Our Crude Oil Acquisition and Marketing segment reflects the sale of gathered and bulk purchased crude oil. The crude oil acquisition and marketing operations generate substantial revenue and cost of products sold as a result of the significant volume of crude oil bought and sold. However, 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 Crude Oil Acquisition and Marketing segment. The operating results of the Crude Oil Acquisition and Marketing segment 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 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 for the Crude Oil Acquisition and Marketing segment. 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 Acquisition and Marketing segment for the periods presented:



	Successor						Predecessor
	Three Months Ended December 31, 2013		Nine Months Ended September 30, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾		Period from January 1, 2012 to October 4, 2012 ⁽¹⁾		Three Months Ended December 31, 2011		Nine Months Ended September 30, 2011 ⁽²⁾
	(in millions, except for barrel amounts)						(in millions, except for barrel amounts)
Sales and other operating revenue
Unaffiliated customers	$	3,620	$	10,502	$	2,747	$	8,951	$	3,135	$	6,780
Affiliates	346		1,048		139		307		—		247
Intersegment revenue	2		—		2		—		—		1
Total sales and other operating revenue	$	3,968	$	11,550	$	2,888	$	9,258	$	3,135	$	7,028
Depreciation and amortization expense	$	13	$	36	$	11	$	16	$	5	$	5
Impairment charge and related matters ⁽³⁾	$	—	$	—	$	—	$	8	$	—	$	—
Adjusted EBITDA	$	33	$	200	$	81	$	158	$	68	$	80
Crude oil purchases (thousands of bpd)	734		754		669		674		690		654
Gross profit per barrel purchased (cents) ⁽⁴⁾	55.9		103.0		138.0		92.8		111.8		49.8
Average crude oil price (per barrel)	$	97.50	$	98.17	$	88.20	$	96.20	$	94.02	$	95.52


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.


⁽²⁾	Includes results from the crude oil acquisition and marketing business acquired from Texon in August 2011 from the acquisition date.


⁽³⁾	In the first quarter 2012, we recognized a non-cash impairment charge related to a cancelled software project.


⁽⁴⁾	Represents total segment sales and other operating revenue minus cost of products sold and operating expenses, divided by crude oil purchases.

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment for the fourth quarter 2013 decreased $48 million compared to the period from October 5, 2012 to December 31, 2012. The decrease in Adjusted EBITDA was primarily due to lower crude oil margins ($56 million) driven by crude differentials which have contracted compared to the prior year period. This impact was partially offset by increased crude oil volumes ($8 million) resulting from the expansion in our crude oil trucking fleet and higher market demand.

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment increased $42 million to $200 million for the nine months ended September 30, 2013, compared to $158 million for the period from January 1, 2012 to October 4, 2012. The increase in Adjusted EBITDA was driven primarily by expanded crude oil volumes ($20 million) and margins ($21 million). Increased volumes resulted from the expansion in our crude oil trucking fleet and market related opportunities in West Texas. Crude oil margins increased over the prior year despite crude differentials which have contracted relative to the first half of 2013.

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment for the period from October 5, 2012 to December 31, 2012 increased $13 million compared to the prior year period due primarily to expanded crude oil margins which were the result of expansion in our crude oil trucking fleet, market related opportunities in West Texas and contributions from the assets acquired from Texon in the third quarter 2011 ($23 million). These improvements were partially offset by overall volume reductions ($2 million) and higher selling, general and administrative expenses ($2 million).

Adjusted EBITDA for the Crude Oil Acquisition and Marketing segment increased $78 million to $158 million for the period from January 1, 2012 to October 4, 2012, as compared to $80 million for the nine months ended September 30, 2011. The increase in Adjusted EBITDA was driven primarily by expanded crude oil volumes and margins which were the result of expansion in our crude oil trucking fleet and market related opportunities in West Texas. Operating results were further improved by increased volumes and margins from the crude oil acquisition and marketing assets acquired from Texon in the third quarter 2011.

Terminal Facilities

Our Terminal Facilities segment consists primarily of crude oil and refined products terminals, including the newly-acquired Marcus Hook Facility, and a refined products acquisition and marketing business. The Terminal Facilities segment earns revenue by providing storage, terminalling, blending and other ancillary services to our customers, as well as through the sale of refined products and NGLs.

The following table presents the operating results and key operating measures for our Terminal Facilities segment for the periods presented:



	Successor						Predecessor
	Three Months Ended December 31, 2013		Nine Months Ended September 30, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾		Period from January 1, 2012 to October 4, 2012 ⁽¹⁾			Three Months Ended December 31, 2011		Nine Months Ended September 30, 2011 ⁽³⁾
	(in millions, except for barrel amounts)						(in millions, except for barrel amounts)
Sales and other operating revenue
Unaffiliated customers	$	175	$	386	$	148	$	264		$	116	$	181
Affiliates	28		111		50		118			34		81
Intersegment revenue	12		39		8		24			6		17
Total sales and other operating revenue	$	215	$	536	$	206	$	406		$	156	$	279
Depreciation and amortization expense	$	26	$	75	$	23	$	28		$	10	$	24
Impairment charge and related matters ⁽²⁾	$	—	$	—	$	—	$	(10	)	$	42	$	—
Adjusted EBITDA	$	62	$	171	$	52	$	173		$	36	$	113
Terminal throughput (thousands of bpd)
Refined products terminals	422		434		451		499			514		485
Nederland terminal	977		917		787		703			692		779
Refinery terminals	324		421		411		369			505		422


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.

⁽²⁾

In the fourth quarter 2011, we recognized a $42 million charge for certain crude oil terminal assets in connection with Sunoco's exit from the refining business. In the second quarter 2012, we recognized a $10 million gain on the reversal of certain regulatory obligations as such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco's joint venture with The Carlyle Group.


⁽³⁾	In July and August 2011, we acquired the Eagle Point tank farm and a refined products terminal located in East Boston, Massachusetts, respectively. Volumes and results for these acquisitions are included from their respective acquisition dates.

Adjusted EBITDA for the Terminal Facilities segment for the fourth quarter 2013 increased $10 million compared to the period from October 5, 2012 to December 31, 2012. The increase in Adjusted EBITDA was due primarily to improved contributions from our Nederland and Eagle Point terminals ($15 million). These increases were partially offset by decreased operating results from our refined products acquisition and marketing activities ($3 million), which was negatively impacted by inventory timing.

Adjusted EBITDA for the Terminal Facilities segment decreased $2 million to $171 million for the nine months ended September 30, 2013, compared to $173 million for the period from January 1, 2012 to October 4, 2012. Results for the first nine months of 2012 included $16 million of non-recurring gains recognized in connection with the sale of the Big Sandy terminal and pipeline assets ($6 million) and the reversal of regulatory obligations ($10 million). Excluding these items, Adjusted EBITDA increased $14 million due primarily to improved results from our Eagle Point and Nederland terminals ($32 million), partially offset by volume reductions at our refined products terminals ($11 million) and higher selling, general and administrative expenses ($7 million).

Adjusted EBITDA for the Terminal Facilities segment for the period from October 5, 2012 to December 31, 2012 increased $16 million compared to the prior year period. During the fourth quarter 2011, we recognized an $11 million charge for certain regulatory obligations which were expected to be incurred if Sunoco's Philadelphia refinery were shut-down. Excluding this amount, Adjusted EBITDA for the Terminal Facilities segment increased $5 million compared to the prior year period due primarily to increased operating results from our refined products acquisition and marketing activities and contributions from organic projects to expand services at our Eagle Point and Nederland terminals ($3 million). Partially offsetting these improvements were decreased volumes at our refined products terminals, increased repair costs resulting from Hurricane Sandy ($3 million) and increased selling, general and administrative expenses.

Adjusted EBITDA for the Terminal Facilities segment increased $60 million to $173 million for the period from January 1, 2012 to October 4, 2012, as compared to $113 million for the nine months ended September 30, 2011. Results for 2012 included non-recurring gains related to the reversal of certain regulatory obligations that were recorded in 2011 ($10 million) and a contract settlement associated with our sale of the Big Sandy terminal and pipeline assets ($6 million). Excluding these items, Adjusted EBITDA increased $44 million due to contributions from the 2011 acquisitions of the Eagle Point tank farm and a refined products terminal in East Boston, Massachusetts ($17 million), operating results from our refined products acquisition and marketing activities ($12 million) and improved results from our Nederland Terminal ($5 million). Partially offsetting these increases were reduced volumes at our refinery terminals related to the idling of Sunoco's Marcus Hook refinery in the fourth quarter 2011 ($4 million) and increased selling, general and administrative expenses ($5 million).

Refined Products Pipelines

Our Refined Products Pipelines segment consists of refined products and NGL pipelines, including a two-thirds undivided interest in the Harbor pipeline and joint-venture interests in four refined products pipelines in selected areas of the United States. The Refined Products Pipeline System primarily earns revenues by transporting refined products from refineries in the northeast, midwest and southwest United States to markets in six states and Canada. Rates for shipments on these pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission ("PA PUC").

The following table presents the operating results and key operating measures for our Refined Products Pipelines segment for the periods presented:



	Successor						Predecessor
	Three Months Ended December 31, 2013		Nine Months Ended September 30, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾		Period from January 1, 2012 to October 4, 2012 ⁽¹⁾		Three Months Ended December 31, 2011		Nine Months Ended September 30, 2011
	(in millions, except for barrel amounts)						(in millions, except for barrel amounts)
Sales and other operating revenue
Unaffiliated customers	$	27	$	68	$	24	$	58	$	20	$	45
Affiliates	7		26		11		36		16		48
Intersegment revenue	—		2		—		2		1		—
Total sales and other operating revenue	$	34	$	96	$	35	$	96	$	37	$	93
Depreciation and amortization expense	$	7	$	18	$	7	$	13	$	4	$	13
Impairment charge and related matters	$	—	$	—	$	—	$	1	$	—	$	—
Adjusted EBITDA	$	13	$	43	$	14	$	57	$	17	$	52
Pipeline throughput (thousands of bpd) ^{(2) (3)}	586		566		601		565		599		496
Pipeline revenue per barrel (cents) ⁽³⁾	63.9		62.0		63.0		62.2		67.5		68.6


⁽¹⁾	The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. The activity from October 1, 2012 through October 4, 2012 was not material in relation to our financial position, results of operations or cash flows.

⁽²⁾


⁽³⁾	Excludes amounts attributable to equity ownership interests in corporate joint ventures which are not consolidated.

Adjusted EBITDA for the Refined Products Pipelines segment for the fourth quarter 2013 decreased $1 million compared to the period from October 5, 2012 to December 31, 2012. The decrease was driven by lower pipeline revenue on reduced throughput volumes.

Adjusted EBITDA for the Refined Products Pipelines segment decreased $14 million to $43 million for the nine months ended September 30, 2013, compared to $57 million for the period from January 1, 2012 to October 4, 2012. Results for 2012 included a $5 million non-recurring gain recognized in connection with the sale of the Big Sandy terminal and pipeline assets and a $6 million non-recurring gain recognized by one of our joint-venture interests. Excluding these items, Adjusted EBITDA decreased $3 million due primarily to higher selling, general and administrative expenses ($7 million), lower pipeline operating gains ($3 million) and higher integrity management costs ($2 million). These factors were partially offset by decreased environmental remediation expenses ($3 million) and higher contributions from our joint-venture interests ($6 million).

Adjusted EBITDA for the Refined Products Pipelines segment for the period from October 5, 2012 to December 31, 2012 decreased $3 million compared to the prior year period due primarily to a shift to shorter pipeline movements at lower average

tariffs ($3 million). Further contributing to the decrease in results were higher selling, general and administrative expenses ($3 million). These decreases were partially offset by lower pipeline operating losses ($2 million).

Adjusted EBITDA for the Refined Products Pipelines segment increased $5 million to $57 million for the period from January 1, 2012 to October 4, 2012, as compared to the nine months ended September 30, 2011. Results for 2012 included a $5 million non-recurring gain recognized in connection with the sale of the Big Sandy terminal and pipeline assets and a $6 million non-recurring gain recognized by one of our joint-venture interests. Excluding these items, Adjusted EBITDA decreased $6 million compared to the prior period. Increased contributions from the acquisition of the Inland refined products pipeline ($5 million) were offset by lower pipeline volumes and fees driven primarily by the idling of the Marcus Hook refinery ($9 million) in the fourth quarter 2011 and increased environmental remediation expenses associated with a pipeline release in the first quarter 2012 ($4 million).

Liquidity and Capital Resources

Liquidity

Cash generated from operations and borrowings under our $1.54 billion in credit facilities are our primary sources of liquidity. At December 31, 2013, we had a net working capital surplus of $337 million and available borrowing capacity of $1.30 billion under our revolving credit facilities. The primary driver of the working capital surplus was the increase in advances to affiliated companies primarily related to borrowings under our credit facilities and increased crude oil and refined products inventories related to operations. Our working capital position reflects crude oil and refined products inventories based on historical costs under the last-in, first-out ("LIFO") method of accounting. We periodically supplement our cash flows from operations with proceeds from debt and equity financing activities.

Capital Resources

Credit Facilities

In November 2013, we replaced our existing $550 million of credit facilities with a new $1.50 billion Credit Facility. The prior credit facilities consisted of a five-year $350 million credit facility and a 364-day $200 million credit facility. Outstanding borrowings under these credit facilities of $119 million at December 31, 2012 were repaid during the first quarter 2013.

The $1.50 billion Credit Facility, which matures in November 2018, includes an "accordion" feature, under which the total aggregate commitment may be extended to $2.25 billion under certain circumstances. The facility is available to fund our working capital requirements, finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants 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, to 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Our ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 2.8 to 1 at December 31, 2013, as calculated in accordance with the credit agreement.

In May 2012, West Texas Gulf entered into a $35 million revolving credit facility (the "$35 million Credit Facility") which expires in April 2015. The facility is available to fund West Texas Gulf's general corporate purposes including working capital and capital expenditures. The credit facility also limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio, as defined in the underlying credit agreement. The ratio for the fiscal quarter ending December 31, 2013 shall not be less than 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf's fixed charge coverage ratio and leverage ratio were 1.12 to 1 and 0.88 to 1, respectively, at December 31, 2013. Outstanding borrowings under this credit facility were $35 and $20 million at December 31, 2013 and 2012, respectively.

Senior Notes

We had $250 million of 7.25 percent Senior Notes which matured and were repaid in February 2012. In addition, our $175 million of 8.75 percent Senior Notes outstanding as of December 31, 2013 matured and were repaid in February 2014 with borrowings under the $1.50 billion Credit Facility.

In January 2013, we issued $350 million of 3.45 percent Senior Notes and $350 million of 4.95 percent Senior Notes (the "2023 and 2043 Senior Notes"), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under our existing senior notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 and $200 million credit facilities and for general partnership purposes.

In July 2011, we issued $300 million of 4.65 percent Senior Notes and $300 million of 6.10 percent Senior Notes (the "2022 and 2042 Senior Notes"), due February 2022 and February 2042, respectively. The net proceeds of $595 million from the 2022 and 2042 Senior Notes were used to pay down outstanding borrowings under prior credit facilities, which were used to fund the acquisitions of a controlling financial interest in Inland and the Texon crude oil acquisition and marketing business, and for general partnership purposes.

Promissory Note, Affiliated Companies

In the fourth quarter 2011, we repaid in full a $100 million subordinated variable-rate promissory note to Sunoco. The note was entered into in July 2010 to fund a portion of the purchase price of our July 2010 acquisition of our butane blending business and was due in May 2013.

Equity Offerings

In July 2011, we issued 3.9 million Class A Units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets. The deferred distribution units were a new class of units that converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net income on a pro-rata basis with the common units. In connection with this transaction, the general partner contributed $2 million to us to maintain its two percent general partner interest.

Subsequent to the filing of our 2013 Form 10-K in February 2014, we filed a registration statement with the intention of establishing an at-the-market equity offering program. The program is subject to regulatory approval and would allow us to issue common units directly to the public and raise capital in a timely and efficient manner to support our growth capital program, while supporting our investment-grade credit ratings.

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 impairment charges. See the Analysis of Consolidated Operating Results, above, for more information on changes in our consolidated earnings.

Net cash provided by operating activities in 2013 of $749 million was primarily the result of net income of $474 million, adjusted for non-cash charges for depreciation and amortization totaling $265 million and a net decrease in working capital of $21 million.

Net cash provided by operating activities in the periods in 2012 of $691 million was primarily the result of net income of $531 million, adjusted for non-cash charges for depreciation and amortization totaling $139 million and a net decrease in working capital of $59 million. The net change in working capital was primarily related to the timing of cash receipts and payments related to accounts receivable and payable, respectively, and increased levels of operating inventories.

Net cash provided by operating activities during 2011 of $430 million was primarily the result of net income of $322 million, adjusted for non-cash charges for depreciation and amortization of $86 million and a $42 million impairment charge. This charge was comprised of a $31 million asset impairment for crude oil terminal assets and $11 million for regulatory obligations in connection with Sunoco's exit from the refining business. These sources were partially offset by a $35 million increase in working capital, which was primarily the result of an increase in accounts receivable and an increase in refined products and crude oil inventories driven by growth within our acquisition and marketing activities. These changes were partially offset by increases in accounts payable.

Investing Activities

Cash flows used in investing activities relate primarily to our capital expenditures, including maintenance and expansion capital expenditures and major acquisitions. See "Capital Requirements" below for additional details on our investing activities.

In addition to cash used for maintenance and expansion capital expenditures, net cash used in investing activities included the $60 million acquisition of the Marcus Hook Facility in 2013, $11 million of proceeds from the sale of the Big Sandy terminal and pipeline assets in 2012, and $396 million related to our four major acquisitions in 2011.

Financing Activities

Cash flows from financing activities relate primarily to the payment of distributions to partners; borrowings and repayments under our credit facilities; the cash impacts of debt and equity activities; and changes in advances to affiliated

companies, which represents our cash held by Sunoco in connection with our participation in Sunoco's cash management program.

Net cash provided by financing activities of $244 million in 2013 was primarily related to $691 million of net proceeds from the January 2013 offering of the 2023 and 2043 Senior Notes and $96 million of net borrowings under our revolving credit facilities. These sources of cash were partially offset by $353 million of distributions to partners and a $183 million increase in advances to affiliated companies.

Net cash used in financing activities of $330 million for the periods in 2012 was primarily attributable to $252 million in distributions paid to the limited partners and the general partner and the $250 million repayment of the 7.25 percent Senior Notes in February 2012. These uses were partially offset by net borrowings under the revolving credit facilities of $139 million.

In 2011, the $182 million of cash provided by financing activities was primarily attributable to $595 million of net proceeds from the issuance of Senior Notes. These proceeds were primarily used to pay down outstanding borrowings under the revolving credit facilities, which were used to finance the acquisitions of the controlling financial interest in Inland and the Texon crude oil acquisition and marketing business, and for general partnership purposes. This source of cash was partially offset by $210 million of quarterly distributions to the limited and general partners; the repayment of the $100 million promissory note to Sunoco; an increase in advances to affiliates of $63 million; and $31 million of net repayments under our revolving credit facilities.

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,


•	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


•	Major 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 year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012		Period from January 1, 2012 to October 4, 2012		Year Ended December 31, 2011
	(in millions)				(in millions)
Expansion	$	965	$	118	$	206	$	171
Maintenance	53		21		29		42
Major Acquisitions	60		—		—		396
Total	$	1,078	$	139	$	235	$	609

In 2013, our expansion capital included projects to: invest in our crude oil infrastructure by increasing our pipeline capabilities through previously announced organic expansion projects in Texas and Oklahoma; expand upon refined products acquisition and marketing services; upgrade the service capabilities at the Eagle Point and Nederland terminals; and invest in the previously-announced Mariner and Allegheny Access projects. Expansion capital expenditures in the 2012 periods also included spending related to investment in our crude oil infrastructure, the expansion of service capabilities at the Eagle Point and Nederland terminals, the Mariner projects and our refined products acquisition and marketing services, in addition to expansion of the crude trucking fleet. Expansion capital for 2011 included projects to expand upon our refined products acquisition and marketing services, increase tankage at the Nederland facility, increase connectivity of the crude oil pipeline assets in Texas and increase our crude oil trucking fleet to meet the demand for transportation services in the southwest United States.

Management expects expansion capital projects to total at least $1.3 billion in 2014, excluding major acquisitions. Projected expansion capital includes spending to capture more value from existing assets such as the Marcus Hook Facility, the

Nederland Terminal and our patented blending technology. Expansion capital expenditures in 2014 will also include continued progress on our previously announced growth projects.

Maintenance capital expenditures primarily consist of recurring expenditures at each of the business segments 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 and related equipment, and the upgrade of pump stations. Management expects maintenance capital expenditures to be approximately $70 million in 2014.

In 2013, major acquisitions consisted of the acquisition of the Marcus Hook Facility from Sunoco for $60 million including acquisition costs.

Major acquisitions during the year ended December 31, 2011 included the East Boston, Massachusetts terminal, the Texon crude oil purchasing and marketing business, the Eagle Point tank farm and an 83.8 percent controlling financial interest in Inland which owns a refined products pipeline system in Ohio.

We expect to fund our capital expenditures, including any additional acquisitions, from cash provided by operations, with proceeds from debt and equity offerings and, to the extent necessary, from the proceeds of borrowings under the credit facilities.

Contractual Obligations

The following table sets forth the aggregate amount of long-term debt maturities, annual rentals applicable to non-cancelable operating leases, and purchase commitments related to future periods at December 31, 2013:



	Year Ended December 31,										Thereafter		Total
	2014		2015		2016		2017		2018		Thereafter		Total
	(in millions)
Long-term debt:
Principal ⁽¹⁾	$	175	$	35	$	175	$	—	$	200	$	1,800	$	2,385
Interest	115		106		101		96		95		1,346		1,859
Operating leases	6		6		5		3		1		1		22
Purchase obligations	3,528		817		815		813		810		3,232		10,015
	$	3,824	$	964	$	1,096	$	912	$	1,106	$	6,379	$	14,281


⁽¹⁾	Includes amounts outstanding at December 31, 2013 related to our 8.75 percent Senior Notes that were repaid in February 2014 with borrowings under our $1.50 billion Credit Facility.

Our operating leases 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 for terms of one year or less by our Crude Oil Acquisition and Marketing segment and non-cancelable contracts to purchase butane for terms of one year or less by our refined products acquisition and marketing business.

A significant portion of the above purchase obligations relate to actual crude oil purchases for the month of January 2014. 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, 2013 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 Acquisition and Marketing."

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."

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.

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. Significant 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 consisting of throughput contracts and historical shipping rights, and technology related assets, which consist of 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 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 also 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.

In 2012, we recognized a non-cash impairment charge of $9 million related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas. In 2011, we recognized a $42 million charge for certain crude oil terminal assets which would have been negatively impacted if Sunoco had permanently idled its Philadelphia refinery. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if these assets were permanently idled. In September 2012, Sunoco completed the formation of PES, a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. As a result, we reversed $10 million of regulatory obligations in the second quarter 2012 which were no longer expected to be incurred. For further discussion, see "Agreements with Related Parties" discussed below. In 2010, we recognized an impairment of $3 million related to the cancellation of a terminal construction project.

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.

Management's process of evaluating goodwill for impairment involves estimating the fair value of our reporting units that contain goodwill. Inherent in estimating the fair value for each reporting unit are certain judgments and estimates relating to market multiples for comparable businesses, including management's interpretation of current economic indicators and market conditions, and assumptions about our strategic plans with regard to our operations. To the extent additional information arises, market conditions change or our strategies change, it is possible that the conclusion regarding whether the goodwill is impaired could change and result in future goodwill impairment charges.

Fair value is estimated using a market multiple methodology whereby multiples of business enterprise value to EBITDA of comparable companies are used to estimate the fair value of the reporting units. Management establishes fair value by comparing the reporting unit to other companies that are similar, from an operational or industry standpoint, and considers the risk characteristics in order to determine the risk profile relative to the comparable companies as a group. The most significant assumptions are the market multiplies.

Environmental Remediation. At December 31, 2013, our accrual for environmental remediation activities was $5 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, 2013. 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 any recently issued accounting pronouncements requiring adoption subsequent to December 31, 2013, see Note 2 to the consolidated financial statements included in Item 8. "Financial Statements and Supplementary Data."

Agreements with Related Parties

Acquisition of Sunoco

The general and limited partner interests that were previously owned by Sunoco were contributed to ETP in connection with the acquisition of Sunoco by ETP. As a result of these transactions, both SXL and Sunoco became consolidated subsidiaries of ETP. We have various operating and administrative agreements with ETP and its affiilates, including the agreements described below. ETP and its affiliates perform the administrative functions defined in such agreements on our behalf. We continue to work with ETP in determining how the acquisition will impact these agreements going forward.

Other Transactions

In March 2011, Sunoco completed the sale of its Toledo, Ohio refinery to affiliates of PBF Holding Company LLC ("PBF"). Certain agreements with Sunoco to supply or purchase crude oil and provide pipeline and terminalling services to support the Toledo refinery were assigned to PBF or its agents in connection with the sale. In September 2011, Sunoco announced its intention to exit its refining business in the northeast and initiated a process to sell its refineries located in Philadelphia and Marcus Hook, Pennsylvania. In December 2011, the main processing units at the Marcus Hook refinery were idled indefinitely. Management assessed the impact that Sunoco’s decision to exit its refining business in the northeast would have on our assets that historically served the refineries and determined that our refined products pipeline and terminal assets continued to have expected future cash flows that support their carrying values. However, we recognized a $42 million charge in the fourth quarter 2011 for crude oil terminal assets which would have been negatively impacted if the Philadelphia refinery was permanently idled. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if these assets were permanently idled. In September 2012, Sunoco completed the formation of PES, a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. During the second quarter 2012, we reversed $10 million of regulatory obligations which were no longer expected to be incurred.

Service and Commodity Sales Agreements

Sunoco utilizes our pipeline and terminal assets to supply refined products to its retail marketing network. Some of these services are provided to Sunoco and its affiliates (including PES) pursuant to agreements with terms that expire at various times as described below, and some are pursuant to agreements that are short term in nature or subject to termination by either party. Management expects that Sunoco will continue to utilize these services for the foreseeable future.

We are party to the following material agreements with our affiliated entities:


•	We have a five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through our terminals. The agreement contains no minimum throughput obligations for Sunoco. The agreement runs through February 2017.

•

We have an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver a minimum average of 300,000 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.


•	We have a three-year agreement with Sunoco to provide approximately 2.0 million barrels of storage capacity and terminalling services to Sunoco at the Eagle Point tank farm which we acquired from Sunoco in 2011. The agreement expires in June 2014. Sunoco does not have exclusive use of the Eagle Point tank farm.

•

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 2011 through 2013.


•	In connection with our second quarter 2013 acquisition of the Marcus Hook Facility, we assumed an agreement to provide butane storage and terminal services to PES at the facility. The 10 year agreement extends through September 2022.


•	We have agreements with Sunoco whereby Sunoco purchases refined products, at market-based rates, at certain of our terminal facilities. These agreements are negotiated annually and currently do not extend beyond 2014.


•	We have agreements with PES whereby PES purchases crude oil, at market-based rates, for delivery to our Fort Mifflin and Eagle Point terminal facilities. These agreements contain minimum volume commitments and extend through 2014.

The renegotiated terms of the agreements with PES 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.

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 the 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 Sunoco an annual administrative fee that includes expenses incurred by Sunoco and its affiliates to perform centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $15, $5, $13 and $13 million for the year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. These fees do not include the costs of shared insurance programs (which are allocated to us based upon our 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 initial term 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) was through the end of 2004. The parties have extended the term of Section 4.1 annually by one year in each year following 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.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the consolidated statements of comprehensive income include the allocation of shared insurance costs of $9, $2, $5 and $4 million for the year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. Our share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $36, $10, $28 and $26 million for the year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. These expenses are reflected in cost of products sold and 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, West Texas Gulf and Inland, as well as the Eagle Point tank farm 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 multiparty 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.

Treasury Services Agreement

We have a treasury services agreement with Sunoco pursuant to which, among other things, we participate in Sunoco's centralized cash management program. Under this program, all of the cash receipts and cash disbursements are processed, together with those of Sunoco and its subsidiaries, through Sunoco’s cash accounts with a corresponding credit or charge to an affiliated account. The affiliated balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco and its subsidiaries earn interest at a rate equal to the average rate of our third-party money market investments, while amounts due to Sunoco and its subsidiaries bear interest at a rate equal to the interest rate provided in the $1.50 billion Credit Facility. In the fourth quarter 2013, we established separate cash accounts to process our own cash receipts and disbursements. Upon completion of the transition for our customers and vendors in 2014, we will cease participation in Sunoco's cash management program.



ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including changing interest rates and volatility in crude oil, refined products and NGL commodity prices. To manage such exposure, interest rates, inventory levels and expectations of future 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, 2013, we had $235 million of variable-rate borrowings under our revolving 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 2 percent at December 31, 2013. A one percent change in the weighted average rate would have impacted annual interest expense by approximately $2 million.

At December 31, 2013, we had $2.15 billion of fixed-rate borrowings which was comprised of our outstanding senior notes. This amount excludes the $120 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 $2.17 billion at December 31, 2013. A hypothetical one-percent decrease in interest rates would increase the fair value of our fixed-rate borrowings at December 31, 2013 by approximately $205 million.

Commodity Market Risk

We are exposed to volatility in crude oil, refined products and NGL commodity prices. To manage such exposures, inventory levels and expectations of future commodity prices are monitored when making decisions with respect to risk management and inventory carried. 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, refined products or NGL 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 refined products and NGL purchase and sale activities. These derivatives are intended to have equal and opposite effects of the purchase and sale activities. At December 31, 2013, the fair market value of our open derivative positions was a net liability of $2 million on 1.6 million barrels of refined products and NGLs. These derivative positions vary in length but do not extend beyond one year. The potential decline in the market value of these derivatives from a hypothetical 10-percent adverse change in the year-end market prices of the underlying commodities that were being hedged by derivative contracts at December 31, 2013 was estimated to be $1 million. 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 contract 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."



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, 2013. 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 1992 Internal Control—Integrated Framework.

Based on this assessment, management believes that, as of December 31, 2013, 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

Martin Salinas, Jr.

Chief Financial Officer

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, 2013, based on criteria established in the 1992 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, 2013, based on criteria established in the 1992 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, 2013, and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Philadelphia, Pennsylvania

February 27, 2014

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 sheet of Sunoco Logistics Partners L.P. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2013, and the related consolidated statements of comprehensive income, cash flows, and equity for the year ended December 31, 2013. 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 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 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 audit provides 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, 2013, and the results of their operations and their cash flows for the year ended December 31, 2013 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, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2014 expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Philadelphia, Pennsylvania

February 27, 2014

REPORT OF ERNST & YOUNG LLP, INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM ON FINANCIAL STATEMENTS

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. (the "Partnership") as of December 31, 2012 (successor), and the related consolidated statements of comprehensive income, equity, and cash flows for the period from October 5, 2012 to December 31, 2012 (successor), the period from January 1, 2012 to October 4, 2012 (predecessor) and the year ended December 31, 2011 (predecessor). 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 consolidated financial position of Sunoco Logistics Partners L.P. at December 31, 2012 (successor) and the consolidated results of its operations and its cash flows for the period from October 5, 2012 to December 31, 2012 (successor), the period from January 1, 2012 to October 4, 2012 (predecessor) and the year ended December 31, 2011 (predecessor), in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

March 1, 2013

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions, except units and per unit amounts)



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31, 2011
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	15,073		$	2,989		$	9,460		$	10,473
Affiliates (Note 4)	1,566			200			461			432
Gain on divestment and related matters (Note 19)	—			—			11			—
Total Revenues	16,639			3,189			9,932			10,905
Costs and Expenses
Cost of products sold	15,574			2,885			9,214			10,153
Operating expenses	117			48			97			111
Selling, general and administrative expenses	123			34			86			90
Depreciation and amortization expense	265			63			76			86
Impairment charge and related matters (Notes 2, 18 and 19)	—			—			(1		)	42
Total Costs and Expenses	16,079			3,030			9,472			10,482
Operating Income	560			159			460			423
Net interest cost to affiliates (Note 4)	(1		)	—			—			(3		)
Other interest cost and debt expense, net	(97		)	(18		)	(73		)	(93		)
Capitalized interest	21			4			8			7
Other income	21			5			18			13
Income Before Provision for Income Taxes	504			150			413			347
Provision for income taxes (Note 2)	(30		)	(8		)	(24		)	(25		)
Net Income	474			142			389			322
Net Income attributable to noncontrolling interests	(11		)	(3		)	(8		)	(9		)
Net Income attributable to Sunoco Logistics Partners L.P.	$	463		$	139		$	381		$	313

Calculation of Limited Partners' interest:
Net Income attributable to Sunoco Logistics Partners L.P.	$	463		$	139		$	381		$	313
Less: General Partner's interest	(124		)	(24		)	(55		)	(54		)
Limited Partners’ interest ⁽¹⁾	$	339		$	115		$	326		$	259

Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit (Note 5):
Basic	$	3.27		$	1.11		$	3.15		$	2.56
Diluted	$	3.25		$	1.10		$	3.14		$	2.54

Weighted average Limited Partners' units outstanding (Note 5):
Basic	103.8			103.8			103.5			101.3
Diluted	104.3			104.1			103.9			101.8

Net Income	$	474		$	142		$	389		$	322
Gain (loss) on cash flow hedges	—			—			(21		)	4
Other Comprehensive Income (Loss)	—			—			(21		)	4
Comprehensive Income	474			142			368			326
Less: Comprehensive income attributable to noncontrolling interests	(11		)	(3		)	(8		)	(9		)
Comprehensive Income attributable to Sunoco Logistics Partners L.P.	$	463		$	139		$	360		$	317


⁽¹⁾	Includes interest in net income attributable to Class A units, which were converted to common units in July 2012.

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

(in millions)



	Successor
	December 31,
	2013			2012
Assets
Cash and cash equivalents	$	39		$	3
Advances to affiliated companies (Note 4)	239			56
Accounts receivable, affiliated companies (Note 4)	11			19
Accounts receivable, net	2,184			1,834
Inventories (Note 6)	600			478
Total Current Assets	3,073			2,390
Properties, plants and equipment	6,785			5,673
Less accumulated depreciation and amortization	(266		)	(50		)
Properties, plants and equipment, net (Note 7)	6,519			5,623
Investment in affiliates (Note 8)	125			118
Goodwill (Note 9)	1,346			1,368
Intangible assets, net (Note 9)	794			843
Other assets	40			19
Total Assets	$	11,897		$	10,361
Liabilities and Equity
Accounts payable	$	2,451		$	1,912
Accounts payable, affiliated companies (Note 4)	17			12
Accrued liabilities	197			147
Accrued taxes payable (Note 2)	71			60
Total Current Liabilities	2,736			2,131
Long-term debt (Note 10)	2,503			1,732
Other deferred credits and liabilities	80			60
Deferred income taxes (Note 2)	253			243
Total Liabilities	5,572			4,166
Commitments and contingent liabilities (Note 11)
Equity
Sunoco Logistics Partners L.P. equity
Limited Partners' interests (103,849,801 and 103,773,003 units outstanding at December 31, 2013 and 2012, respectively)	5,292			5,175
General Partner's interest	912			897
Total Sunoco Logistics Partners L.P. equity	6,204			6,072
Noncontrolling interests	121			123
Total Equity	6,325			6,195
Total Liabilities and Equity	$	11,897		$	10,361

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31, 2011
Cash Flows from Operating Activities:
Net Income	$	474		$	142		$	389		$	322
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	265			63			76			86
Impairment charge and related matters	—			—			(1		)	42
(Claim for) recovery of environmental liability	—			13			(14		)	—
Expected proceeds from insurance recovery	(1		)	—			—			—
Deferred income tax expense (benefit)	6			(2		)	—			(2		)
Amortization of financing fees and bond discount	1			—			2			2
Amortization of bond premium	(23		)	(6		)	—			—
LTIP expense (Note 14)	14			2			6			6
Changes in working capital pertaining to operating activities:
Accounts receivable, affiliated companies	8			(18		)	(1		)	154
Accounts receivable, net	(351		)	162			190			(647		)
Inventories	(117		)	(70		)	(44		)	(108		)
Accounts payable and accrued liabilities	468			4			(174		)	548
Accounts payable, affiliated companies	2			12			—			—
Accrued taxes payable	11			4			(6		)	18
Other	(8		)	(26		)	(12		)	9
Net cash provided by operating activities	749			280			411			430
Cash Flows from Investing Activities:
Capital expenditures	(897		)	(139		)	(235		)	(213		)
Acquisitions	(60		)	—			—			(396		)
Proceeds from divestments and related matters	—			—			11			—
Net cash used in investing activities	(957		)	(139		)	(224		)	(609		)
Cash Flows from Financing Activities:
Distributions paid to limited and general partners	(353		)	(74		)	(178		)	(210		)
Distributions paid to noncontrolling interests	(13		)	(2		)	(5		)	(8		)
Contributions from general partner	—			—			—			2
Payments of statutory withholding on net issuance of limited partner units under LTIP	(3		)	(7		)	(5		)	(3		)
Repayments under credit facilities	(119		)	(233		)	(322		)	(560		)
Borrowings under credit facilities	215			193			501			529
Net proceeds from issuance of long-term debt	691			—			—			595
Repayments of senior notes	—			—			(250		)	—
Promissory note from affiliate	—			—			—			(100		)
Advances to affiliated companies, net	(183		)	(17		)	69			(63		)
Contributions attributable to acquisition from affiliate	9			—			—			—
Net cash provided by (used in) financing activities	244			(140		)	(190		)	182
Net change in cash and cash equivalents	36			1			(3		)	3
Cash and cash equivalents at beginning of period	3			2			5			2
Cash and cash equivalents at end of period	$	39		$	3		$	2		$	5

(See Accompanying Notes)

SUNOCO LOGISTICS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF EQUITY

(in millions)



	Limited Partners									General Partner			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total
	Common				Class A
	Units	$			Units		$			$			$			$			$
Predecessor
Balance at December 31, 2010	99.2	$	940		—		$	—		$	28		$	(3	)	$	77		$	1,042
Net Income	—	$	257		—		$	2		$	54		$	—		$	9		$	322
Gain on cash flow hedges	—	—			—		—			—			4			—			4
Total comprehensive income	—	257			—		2			54			4			9			326
Issuance of Class A units to Sunoco, Inc.	—	—			3.9		20			2			—			—			22
Units issued under LTIP	0.2	6			—		—			—			—			—			6
Distribution equivalent rights	—	(2		)	—		—			—			—			—			(2		)
Payment of statutory withholding on issuance under LTIP	—	(3		)	—		—			—			—			—			(3		)
Noncontrolling equity in joint venture acquisitions	—	—			—		—			—			—			20			20
Distributions	—	(160		)	—		—			(50		)	—			(8		)	(218		)
Other	—	1			—		—			—			—			—			1
Balance at December 31, 2011	99.4	$	1,039		3.9		$	22		$	34		$	1		$	98		$	1,194
Net Income	—	$	324		—		$	2		$	55		$	—		$	8		$	389
Loss on cash flow hedges	—	—			—		—			—			(21		)	—			(21		)
Total comprehensive income (loss)	—	324			—		2			55			(21		)	8			368
Units issued under LTIP	0.3	6			—		—			—			—			—			6
Distribution equivalent rights	—	(1		)	—		—			—			—			—			(1		)
Payment of statutory withholding on issuance under LTIP	—	(5		)	—		—			—			—			—			(5		)
Conversion of Class A units to common units	3.9	24			(3.9	)	(24		)	—			—			—			—
Distributions	—	(133		)	—		—			(45		)	—			(5		)	(183		)
Balance at October 4, 2012	103.6	$	1,254		—		$	—		$	44		$	(20	)	$	101		$	1,379

Successor
Balance at October 5, 2012	103.6	$	5,118		—		$	—		$	893		$	—		$	123		$	6,134
Net Income	—	$	115		—		$	—		$	24		$	—		$	3		$	142
Total comprehensive income	—	115			—		—			24			—			3			142
Units issued under LTIP	0.2	2			—		—			—			—			—			2
Payment of statutory withholding on issuance under LTIP	—	(7		)	—		—			—			—			—			(7		)
Distributions	—	(54		)	—		—			(20		)	—			(2		)	(76		)
Other	—	1			—		—			—			—			(1		)	—
Balance at December 31, 2012	103.8	$	5,175		—		$	—		$	897		$	—		$	123		$	6,195
Net Income	—	$	339		—		$	—		$	124		$	—		$	11		$	474
Total comprehensive income	—	339			—		—			124			—			11			474
Units issued under LTIP	—	14			—		—			—			—			—			14
Distribution equivalent rights	—	(2		)	—		—			—			—			—			(2		)
Payment of statutory withholding on issuance under LTIP	—	(3		)	—		—			—			—			—			(3		)
Distributions	—	(243		)	—		—			(110		)	—			(13		)	(366		)
Contributions attributable to acquisition from affiliate	—	9			—		—			—			—			—			9
Increase attributable to acquisition from affiliate	—	4			—		—			—			—			—			4
Other	—	(1		)	—		—			1			—			—			—
Balance at December 31, 2013	103.8	$	5,292		—		$	—		$	912		$	—		$	121		$	6,325

(See Accompanying Notes)

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 crude oil, refined products and natural gas liquids ("NGL") pipelines, terminalling and storage assets, and crude oil, refined products and NGL acquisition and marketing assets. The Partnership conducts its business activities in more than 30 states located throughout the United States.

On October 5, 2012, Sunoco, Inc. ("Sunoco") was acquired by Energy Transfer Partners, L.P. ("ETP"). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as the Partnership's general partner and owned a two percent general partner interest, all of the Partnership's incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco's general partner and limited partner interests were contributed to ETP, resulting in a change in control of the Partnership's general partner. As a result, the Partnership became a consolidated subsidiary of ETP and elected to apply "push-down" accounting, which required the Partnership's assets and liabilities to be adjusted to fair value on the closing date, October 5, 2012. The effective date of the acquisition for accounting and reporting purposes was deemed to be October 1, 2012. Due to the application of push-down accounting, the Partnership's consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting during those periods. The periods prior to the acquisition date, October 5, 2012, are identified as "Predecessor" and the periods from October 5, 2012 forward are identified as "Successor." The Partnership performed an analysis and determined that the activity from October 1, 2012 through October 4, 2012 was not material in relation to the Partnership’s financial position, results of operations or cash flows. Therefore, operating results between October 1, 2012 and October 4, 2012 were included within the "Successor" period in the Partnership's 2012 consolidated financial statements.

With the assistance of a third-party valuation firm, management developed models to determine the enterprise value of the Partnership on October 5, 2012. These models utilized a combination of observable market inputs and management assumptions, including the application of a discounted cash flow approach to projected operating results, growth estimates and projected changes in market conditions. The fair value of the partners' capital balances as of October 5, 2012 was as follows:



	(in millions)
Fair value of Limited Partners' interests	$	5,118
Fair value of General Partner's interest	893
Fair value of Noncontrolling interests	123
	$	6,134

The Partnership then determined the fair values of its assets and liabilities. The fair values of the Partnership's current assets and current liabilities (with the exception of inventory) were assumed to approximate their carrying values. The fair values of the Partnership's long-lived tangible assets and inventory were determined utilizing observable market inputs where available or estimated replacement cost adjusted for a usage or obsolescence factor. The Partnership's identifiable intangible assets consist of customer relationships and technology patents, the fair values of which were determined by applying a discounted cash flow approach, which was adjusted for customer attrition assumptions and projected market conditions. The fair values of the Partnership's long-term liabilities were determined utilizing observable market inputs where available or estimated based on their current carrying values. The Partnership recorded goodwill as the excess of the enterprise value over the sum of the fair values of the Partnership's assets and liabilities. The following table summarizes the final allocation of the fair value of partners' capital balances to the assets and liabilities of the Partnership as of the acquisition date. Based on management's review of the valuation, certain amounts included in the purchase price allocation have been adjusted during 2013 from those amounts reflected in the preliminary purchase price allocation as of October 5, 2012. These adjustments did not have a material impact on the Partnership's financial position or results of operations.




	(in millions)
Current assets	$	2,449
Properties, plants and equipment	5,555
Investment in affiliates	119
Goodwill ⁽¹⁾	1,346
Intangible assets	855
Other assets	25
Current liabilities	(2,132		)
Long-term debt	(1,778		)
Other deferred credits and liabilities	(61		)
Deferred income taxes	(244		)
	$	6,134


⁽¹⁾	Includes $200, $545 and $601 million allocated to the Crude Oil Pipelines, Crude Oil Acquisition and Marketing and Terminal Facilities segments, respectively.

In July 2013, the limited liability agreement of Sunoco Partners LLC was amended to reflect the addition of ETE Common Holdings, LLC ("ETE Holdings") as an owner of a 0.1 percent membership interest in the Partnership's general partner. ETE Holdings is a wholly-owned subsidiary of Energy Transfer Equity, L.P., and an affiliate of ETP. This change in the ownership of the general partner did not impact the Partnership's consolidated financial statements. Subsequent to the amendment, the Partnership remains a consolidated subsidiary of ETP. In addition, the 33.5 million common units owned by Sunoco Partners LLC were assigned to ETP.

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 holds a controlling financial interest in Inland Corporation ("Inland"), Mid-Valley Pipeline Company ("Mid-Valley") and West Texas Gulf Pipe Line Company ("West Texas Gulf"), and as such, these joint ventures are reflected as consolidated subsidiaries of the Partnership. 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 corporate 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.

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 the 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.

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, refined products and NGLs 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 crude oil exchange transactions, which are entered into primarily to acquire crude oil 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 and refined products, as well as the provision of crude oil and refined products, pipeline transportation, terminalling and storage services to ETP and its affiliates (including Sunoco). Sales of crude oil 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 an established agreement 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, 2013 and 2012, 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.

Inventories

Inventories are valued at the lower of cost or market. Crude oil 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.

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 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 corporate 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 corporate 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 corporate 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 assets acquired and liabilities assumed as part of 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 in connection with acquisitions from entities under common control are recorded by the Partnership at the 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 equity.

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.

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.

See Note 3 for additional information concerning the Partnership's recent acquisitions.

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.

In September 2011, Sunoco announced its intention to exit its refining business in the northeast and initiated a process to sell its refineries located in Philadelphia and Marcus Hook, Pennsylvania. In December 2011, the main processing units at the Marcus Hook refinery were idled indefinitely. Management assessed the impact that Sunoco's decision to exit its refining business in the northeast would have on the Partnership's assets that historically served the refineries and determined that the Partnership's refined products pipeline and terminal assets continued to have expected future cash flows that support their carrying values. However, the Partnership recognized a $42 million charge in the fourth quarter 2011 for crude oil terminal assets which would have been negatively impacted if the Philadelphia refinery was permanently idled. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if the assets were permanently idled. In September 2012, Sunoco completed the formation of Philadelphia Energy Solutions ("PES"), a joint venture with The Carlyle Group, which enabled the Philadelphia refinery to continue operating. During the second quarter 2012, the Partnership reversed $10 million of regulatory obligations which were no longer expected to be incurred.

The impairment recognized by the Partnership in 2011 was calculated using fair value assumptions, including comparable land sale transactions and current replacement costs of similar new equipment, adjusted to reflect the age, condition, maintenance history and estimated useful life of the assets. Since the fair value assessment reflected both observable and unobservable inputs, it was determined to be a level 3 fair value measurement within the fair value hierarchy under current accounting guidance.

The Partnership also recognized an impairment charge of $9 million in 2012. These charges related to the cancellation of a software project and other costs associated with the write-off of assets that the Partnership could not deploy elsewhere within its operations.

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 determined during 2013, 2012 and 2011 that goodwill was not impaired.

Management's process of evaluating goodwill for impairment involves estimating the fair value of the Partnership's reporting units that contain goodwill. Inherent in estimating the fair value for each reporting unit are certain judgments and estimates relating to market multiples for comparable businesses, management's interpretation of current economic indicators and market conditions, and assumptions about the Partnership's strategic plans with regard to its operations. To the extent additional information arises, market conditions change or the Partnership's strategies change, it is possible that the conclusion regarding whether the goodwill is impaired could change and result in future goodwill impairment charges.

Fair value is estimated using a market multiple methodology whereby the ratios of business enterprise value to earnings before interest, taxes, depreciation and amortization ("EBITDA") of comparable companies are used to estimate the fair value

of the Partnership's reporting units. Management establishes fair value by comparing the reporting unit to other companies that are similar, from an operational or industry perspective, and by considering risk characteristics in order to determine the risk profile relative to the comparable companies as a group. The most significant assumptions are the market multiples.

Intangible Assets

The Partnership has acquired intangible assets such as throughput and deficiency contracts, customer relationships, historical shipping rights 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.

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, 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:



	Successor					Predecessor
	Year Ended December 31, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012		Year Ended December 31, 2011
	(in millions)					(in millions)
Federal
Current	$	21	$	8		$	22	$	25
Deferred	6		(2		)	—		(2		)
State
Current	3		2			2		2
Deferred	—		—			—		—
Total income tax expense	$	30	$	8		$	24	$	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, 2013 and 2012, the Partnership had $253 and $243 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 fair value and reports the related expense within selling, general and administrative expenses in the consolidated statements of comprehensive income. Unit-based compensation cost for awards of restricted units is based on either the fair market value of common units on the grant date using a Monte Carlo Simulation (if the payout is determined by market criteria relative to unit proxies), or 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 issued prior to 2013, the recognition of compensation cost 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 liabilities related to the future retirement of long-lived assets and are recorded at the time a legal obligation is incurred. A corresponding asset is recorded concurrently and is depreciated over the remaining useful life of the related long-lived asset. The fair value of the ARO is determined based on estimates and assumptions regarding retirement costs related to the Partnership's pipelines and storage tanks. The Partnership bases these estimates on historical retirement 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. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.

The Partnership's consolidated balance sheets include AROs as a component of other deferred credits and liabilities of $41 million at December 31, 2013 and 2012. 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.

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 Financial Accounting Standards Board ("FASB"). The Partnership generally applies a "market 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.

Comprehensive Income

The components of net income and other comprehensive income are presented in the Partnership's consolidated statements of comprehensive income. In February 2013, the FASB codified guidance related to the presentation and disclosure of components reclassified out of accumulated other comprehensive income (loss). The adoption of the new guidance, effective for the Partnership beginning January 1, 2013, did not have a material impact on the Partnership's consolidated financial statements and disclosures.

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 A 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 and limited partners based on the contractual terms of the partnership agreement.

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, 2013 and 2011:

2013 Acquisition

•

In the second quarter 2013, the Partnership acquired Sunoco's Marcus Hook facility and related assets (the "Marcus Hook Facility") for $60 million in cash, including acquisition costs. The acquisition included terminalling and storage assets located in Pennsylvania and Delaware and commercial agreements, including a reimbursement agreement under which Sunoco will reimburse the Partnership $40 million for certain operating expenses of the Marcus Hook Facility through March 31, 2017. The reimbursement proceeds will be reflected as contributions to equity. The Partnership will be indemnified against environmental liabilities resulting from events which occurred at the Marcus Hook Facility prior to the closing of the transaction. Since the transaction was with an entity under common control, the assets acquired and liabilities assumed were recorded by the Partnership at Sunoco's net carrying value plus acquisition costs. The difference between Sunoco's net carrying value and the consideration transferred was recorded by the Partnership as an increase to equity. The acquisition was included within the Terminal Facilities segment.

The following table summarizes the effects of the 2013 acquisition on the Partnership's consolidated balance sheet:



	Marcus Hook Facility
	(in millions)
Increase in:
Current assets	$	6
Properties, plants and equipment, net	66
Other assets	8
Current liabilities	(1		)
Other deferred credits and liabilities	(15		)
Sunoco Logistics Partners L.P. equity	(4		)
Cash paid for acquisition	$	60

2011 Acquisitions

•

In August 2011, the Partnership acquired a refined products terminal, located in East Boston, Massachusetts, from affiliates of ConocoPhillips for $56 million plus the fair value of inventory. The terminal includes a 10-bay truck rack and tanks providing approximately 1 million barrels of storage capacity and is the sole service provider to Logan International Airport under a long-term contract to supply jet fuel. The acquisition was included within the Terminal Facilities segment.

•

In August 2011, the Partnership acquired a crude oil purchasing and marketing business from Texon L.P. ("Texon") for $205 million plus the fair value of its crude oil inventory. The purchase consisted of a crude oil acquisition and marketing business and gathering assets for approximately 75,000 barrels per day at the wellhead in 16 states, primarily in the western United States. The acquisition was included within the Crude Oil Acquisition and Marketing segment.

•

In July 2011, the Partnership acquired the Eagle Point tank farm and related assets from Sunoco for $100 million. The tank farm is located in Westville, New Jersey and has approximately 5 million barrels of active storage capacity for refined products and dark oils. The acquisition was funded by the issuance of 3.9 million Class A units with an estimated market value of $98 million and payment of $2 million of cash to Sunoco. The Class A units were a new class of units on which no distributions were paid until the Class A units converted to common units in July 2012. As the acquisition was from an entity under common control, the assets acquired were recorded by the Partnership at Sunoco's net carrying value of $22 million. The $20 million difference between the carrying value of the assets and the cash consideration paid was recorded by the Partnership as an increase to equity. The acquisition was included within the Terminal Facilities segment.

•

In May 2011, the Partnership acquired an 83.8 percent equity interest in Inland, which is the owner of 350 miles of active refined products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminals and major markets in Ohio. The Partnership acquired its equity interest for $99 million, net of cash received, through a purchase of a 27.0 percent percent equity interest from Shell Oil Company and a 56.8 percent equity interest from Sunoco. The 56.8 percent equity interest acquired from Sunoco was considered a transaction between entities under common control and therefore the assets and liabilities transferred were recorded by the Partnership at Sunoco's carrying value. As the Partnership acquired a controlling financial interest in Inland, the joint venture was reflected as a consolidated subsidiary of the Partnership from the date of the final acquisition and was included within the Refined Products Pipelines segment.

The following table summarizes the effects of the 2011 acquisitions on the Partnership's consolidated balance sheet as of the respective acquisition dates:



	East Boston Terminal			Crude Oil Acquisition and Marketing			Eagle Point Tank Farm			Inland			Total
	(in millions)
Increase in:
Current assets	$	17		$	24		$	—		$	3		$	44
Properties, plants and equipment, net	63			7			22			178			270
Intangible assets, net	—			183			—			—			183
Goodwill	—			14			—			—			14
Current liabilities	—			(6		)	—			(1		)	(7		)
Other deferred credits and liabilities	(7		)	—			—			(1		)	(8		)
Deferred income taxes	—			—			—			(60		)	(60		)
Sunoco Logistics Partners L.P. equity	—			—			(20		)	—			(20		)
Noncontrolling interests	—			—			—			(20		)	(20		)
Cash paid for acquisitions	$	73		$	222		$	2		$	99		$	396

No pro forma information has been presented since the impact of the acquisitions during 2013 and 2011 was not material in relation to the Partnership's consolidated results of operations or financial position.

4. Related Party Transactions

Acquisition of Sunoco

The general and limited partner interests that were previously owned by Sunoco were contributed to ETP in connection with the acquisition of Sunoco by ETP (Note 1). As a result of the acquisition, both the Partnership and Sunoco became consolidated subsidiaries of ETP. 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 its affiliates including agreements to provide pipeline and terminalling services and to supply crude oil and refined products. Some of these agreements are long-term and expire at various times as described below, while others short-term in nature or subject to termination by either party. Affiliated revenues in the consolidated statements of comprehensive income relate to services including pipeline transportation, terminalling, storage and blending, and the sale of crude oil and refined products.

The Partnership had the following material agreements with its affiliated entities at December 31, 2013:


•	Product Terminal Services Agreement: The Partnership has a five-year product terminal services agreement with Sunoco under which Sunoco may throughput refined products through 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 PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 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 a 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.


•	Eagle Point Terminal Services Agreement: The Partnership has a three-year agreement with Sunoco to provide approximately 2.0 million barrels of storage capacity and terminalling services to Sunoco at the Eagle Point tank farm. The agreement expires in June 2014. Sunoco does not have exclusive use of the Eagle Point tank farm.

•

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 Facility 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 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 2011 through 2013.


•	Butane Storage and Terminalling Services Agreement: In connection with the second quarter 2013 acquisition of the Marcus Hook Facility, 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 Product Sales: The Partnership has agreements with Sunoco whereby Sunoco purchases refined products, at market-based rates, at certain of the Partnership's terminal facilities. These agreements are negotiated annually and currently do not extend beyond 2014.


•	Crude Oil Sales: The Partnership has agreements with PES whereby PES purchases crude oil, at market-based rates, for delivery to the Partnership's Fort Mifflin and Eagle Point terminal facilities. These agreements contain minimum volume commitments and extend through 2014.

Sunoco continues to utilize the Partnership's pipeline and terminal assets to supply its retail marketing network in an efficient manner. All pipeline movements are on the same terms that would be available to an unrelated third party and are based on published tariff rates on the respective pipelines. Management expects that Sunoco will continue to utilize these services for the foreseeable future.

Advances to/from Affiliate

The Partnership has a treasury services agreement with Sunoco pursuant to which it, among other things, participates in Sunoco's centralized cash management program. Under this program, all of the Partnership's cash receipts and cash disbursements are 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 affiliated balances are settled periodically, but no less frequently than monthly. Amounts due from Sunoco earn interest at a rate equal to the average rate provided by the Partnership's third-party money market investments, while amounts due to Sunoco bear interest at a rate equal to the interest rate on the Partnership's $1.50 billion Credit Facility (Note 10). In the fourth quarter 2013, the Partnership established separate cash accounts to process its own cash receipts and disbursements. Upon completion of the transition for the Partnership's customers and vendors in 2014, the Partnership will cease participation in Sunoco's cash management program.

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.

Under the Omnibus Agreement, the Partnership pays Sunoco an annual administrative fee that includes expenses incurred by Sunoco to perform certain centralized corporate functions, such as legal, accounting, treasury, engineering, information technology, insurance, and other corporate services, including the administration of employee benefit plans. This fee was $15, $5, $13 and $13 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. 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.

In addition to the fees for the centralized corporate functions, selling, general and administrative expenses in the consolidated statements of comprehensive income include the allocation of shared insurance costs of $9, $2, $5 and $4 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. The Partnership's share of allocated Sunoco employee benefit plan expenses, including non-contributory defined benefit retirement plans, defined contribution 401(k) plans, employee and retiree medical, dental and life insurance plans, incentive compensation plans and other such benefits was $36, $10, $28 and $26 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011. These expenses are reflected in cost of products sold and 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 (including Sunoco) to supply crude oil 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 and refined products and services including pipeline transportation, terminalling, storage and blending.

Capital Contributions

In July 2011, the Partnership issued 3.9 million Class A Units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets (Note 3). As this transaction was between entities under common control, accounting guidance required the issuance to be recorded at the net of Sunoco's historical carrying value of the assets acquired ($22 million) and the $2 million cash consideration paid. The $20 million of deferred distribution units were a new class of units that were converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net income on a pro-rata basis with the common units. In connection with this transaction, the general partner contributed $2 million to the Partnership. The Partnership recorded this amount as a capital contribution to Equity within its consolidated balance sheet.

During 2013, the Partnership issued less than 0.1 million limited partnership units, and during 2012 and 2011, the Partnership issued 0.5, and 0.2 million limited partnership units, respectively, to participants in the Sunoco Partners LLC Long-Term Incentive Plan upon completion of award vesting requirements. As a result of these issuances of limited partnership units, the general partner contributed less than $0.5 million in each period to the Partnership to maintain its two percent general partner interest. The Partnership recorded these amounts as capital contributions to Equity within its consolidated balance sheets.

5. Net Income Attributable to Sunoco Logistics Partners L.P. Per Limited Partner Unit Data

The general partner's interest in net income attributable to SXL consists of its two percent general partner interest and "incentive distributions," which are increasing percentages, up to 50 percent of quarterly distributions in excess of $0.1667 per limited partner unit (Note 13). The general partner was allocated net income attributable to SXL of $124 million (representing 27 percent of total net income attributable to SXL) for the year ended December 31, 2013, $24 million (representing 17 percent of total net income attributable to SXL) for the period from October 5, 2012 to December 31, 2012, $55 million (representing 14 percent of total net income attributable to SXL) for the period from January 1, 2012 to October 4, 2012, and $54 million (representing 17 percent of total net income attributable to SXL) for the year ended December 31, 2011. 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 common and Class A units outstanding, prior to conversion to common units (Note 12), and the dilutive effect of incentive unit awards (Note 14).

The following table sets forth the reconciliation of the weighted average number of limited partner 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:



	Successor		Predecessor
	Year Ended December 31, 2013	Period from Acquisition (October 5, 2012) to December 31, 2012	Period from January 1, 2012 to October 4, 2012	Year Ended December 31, 2011
	(in millions)		(in millions)
Weighted average number of units outstanding—basic	103.8	103.8	103.5	101.3
Add effect of dilutive incentive awards	0.5	0.3	0.4	0.5
Weighted average number of units—diluted	104.3	104.1	103.9	101.8

6. Inventories

The components of inventories are as follows:



	Successor
	December 31,
	2013		2012
	(in millions)
Crude oil	$	488	$	418
Refined products	99		48
Refined products additives	3		3
Materials, supplies and other	10		9
	$	600	$	478

The current replacement cost of crude oil and refined products inventory exceeded its carrying value by $68 and $7 million at December 31, 2013 and 2012, respectively. The increase in refined products inventories in 2013 was primarily attributable to the expansion of refined products acquisition and marketing activities in connection with the newly acquired Marcus Hook Facility.

7. Properties, Plants and Equipment

The components of net properties, plants and equipment are as follows:



		Successor
		December 31,
	Estimated Useful Lives	2013			2012
	(in years)	(in millions)
Land and land improvements (including rights of way) ⁽¹⁾	—	$	1,101		$	1,026
Pipelines and related assets	38 - 60	3,172			2,687
Terminals and storage facilities	5 - 44	1,081			934
Other	5 - 48	463			647
Construction-in-progress		968			379
Total properties, plants and equipment		6,785			5,673
Less: Accumulated depreciation and amortization		(266		)	(50		)
Total properties, plants and equipment, net		$	6,519		$	5,623


⁽¹⁾	As of December 31, 2013 and 2012, the Partnership has rights of way with a book value of $940 and $939 million, respectively.

As of December 31, 2013 and 2012, accrued capital expenditures were $137 and $16 million, respectively.

8. Investment in Affiliates

The active corporate joint ventures own refined products pipeline systems. The Partnership's ownership percentages in corporate joint ventures as of December 31, 2013 and 2012 were as follows:



	Successor
	December 31,
	2013	2012
Explorer Pipeline Company	9.4%	9.4%
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%
SunVit Pipeline LLC	50.0%	—%

In the third quarter 2013, the Partnership entered into an agreement to form SunVit Pipeline LLC ("SunVit"), a joint venture with Vitol, Inc. ("Vitol"), in which each party will maintain a 50 percent ownership interest. SunVit will construct and own a crude oil pipeline, which will originate in Midland, Texas and run to Garden City, Texas. The new pipeline will connect to the Partnership's existing pipelines and along with the Partnership's Permian Express 2 pipeline project, will provide additional takeaway capacity from the Permian Basin. SunVit is expected to commence operations in 2015. Under the terms of the joint-venture agreement, each owner will fund construction of the pipeline and operating expenses in proportion with its ownership interest. Per the agreement, during the fourth quarter 2013, the Partnership and Vitol each accrued $3 million of contributions to cover initial construction costs. SunVit is reflected as an equity-method investment within the Partnership's Crude Oil Pipelines segment.

The Partnership's investments in Yellowstone Pipe Line Company, West Shore Pipe Line Company and Wolverine Pipe Line Company at December 31, 2013 included net excess investment amounts of $89 million. The excess investment is the difference between the investment balances and the Partnership's proportionate share of the net assets of the entities. The Partnership has not provided additional financial support to any of the refined products joint ventures during the 2011 through 2013 periods.

The Partnership had $37 million of undistributed earnings from its investments in corporate joint ventures within Equity at December 31, 2013. During the year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, the Partnership recorded equity income of $21, $5, $15 and $12 million, respectively, and received dividends of $14, $6, $5 and $11 million, respectively, from its investments in corporate joint ventures.

9. Goodwill and Other Intangible Assets

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 subject to impairment testing at least annually. The Partnership's goodwill balance at December 31, 2013 and 2012 was $1,346 and $1,368 million, respectively. The decrease in the Partnership's goodwill balance related to adjustments made during the measurement period to the fair values of the Partnership's assets and liabilities resulting from the application of push-down accounting in connection with the acquisition of the general partner by ETP (Note 1).

Identifiable Intangible Assets

The Partnership's identifiable intangible assets are comprised of customer relationships, which consist of throughput contracts and historical shipping rights, 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 $49, $12, $20 and $15 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively.

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.



		Successor
		December 31,
	Weighted Average Amortization Period	2013			2012
	(in years)	(in millions)
Gross
Customer relationships	18	$	808		$	808
Technology	10	47			47
Total gross		855			855
Accumulated amortization
Customer relationships		(56		)	(11		)
Technology		(5		)	(1		)
Total accumulated amortization		(61		)	(12		)
Total Net		$	794		$	843

As of December 31, 2013, the Partnership forecasts $49 million of annual amortization expense for each year through the year 2018 for these 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, 2013 and December 31, 2012.

10. Debt

The components of the Partnership's long-term debt balances are as follows:



	Successor
	December 31,
	2013			2012
	(in millions)
Credit Facilities
$1.50 billion Credit Facility, due November 2018	$	200		$	—
$350 million Credit Facility, terminated November 2013 ⁽¹⁾	—			93
$200 million Credit Facility, terminated November 2013 ⁽¹⁾	—			26
$35 million Credit Facility, due April 2015	35			20
Senior Notes
Senior Notes - 8.75%, due February 2014⁽²⁾	175			175
Senior Notes - 6.125%, due May 2016	175			175
Senior Notes - 5.50%, due February 2020	250			250
Senior Notes - 4.65%, due February 2022	300			300
Senior Notes - 3.45%, due January 2023	350			—
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			—
Unamortized fair value adjustments (Note 1)	120			143
Total debt	2,505			1,732
Less:
Unamortized bond discount	(2		)	—
Current portion of long-term debt ^{(1) (2)}	—			—
Long-term debt	$	2,503		$	1,732


⁽¹⁾	Amounts outstanding under the Partnership's credit facilities at December 31, 2012 were classified as long-term debt as the Partnership repaid such borrowings with proceeds from the January 2013 senior notes offering.


⁽²⁾	The 8.75 percent Senior Notes were classified as long-term debt at December 31, 2013 as the Partnership repaid these notes in February 2014 with borrowings under its $1.50 billion Credit Facility due in 2018.

The aggregate amount of long-term debt maturities is as follows:



Year Ended December 31,	(in millions)
2014	$	175
2015	35
2016	175
2017	—
2018	200
Thereafter	1,800
Total	$	2,385

Cash payments for interest related to long-term debt, net of capitalized interest (Note 2), were $83, $2, $87 and $73 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively.

Credit Facilities

In November 2013, the Partnership replaced its existing $550 million of credit facilities with a new $1.50 billion unsecured credit facility (the "$1.50 billion Credit Facility"). The $1.50 billion Credit Facility contains an "accordion" feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions. The prior credit facilities consisted of a five-year $350 million credit facility and a 364-day $200 million credit facility. Outstanding borrowings under these credit facilities of $119 million at December 31, 2012 were repaid during the first quarter 2013.

The $1.50 billion Credit Facility, which matures in November 2018, is available to fund the Operating Partnership's working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The $1.50 billion Credit Facility bears interest at LIBOR or the Base Rate (as defined in the facility), each plus an applicable margin. The credit facility may be prepaid at any time. Outstanding borrowings under this credit facility were $200 million at December 31, 2013.

The $1.50 billion Credit Facility various covenants, including limitations on the creation of indebtedness and liens, and other covenants 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, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 2.8 to 1 at December 31, 2013, as calculated in accordance with the credit agreements.

Senior Notes

The Operating Partnership had $250 million of 7.25 percent Senior Notes which matured and were repaid in February 2012. In addition, the Partnership's $175 million of 8.75 percent Senior Notes outstanding as of December 31, 2013 matured and were repaid in February 2014 with borrowings under the $1.50 billion Credit Facility.

In January 2013, the Operating Partnership issued $350 million of 3.45 percent Senior Notes and $350 million of 4.95 percent Senior Notes (the "2023 and 2043 Senior Notes"), due January 2023 and January 2043, respectively. The terms and conditions of the 2023 and 2043 Senior Notes are comparable to those under the Operating Partnership's existing senior notes. The net proceeds of $691 million from the 2023 and 2043 Senior Notes were used to pay outstanding borrowings under the $350 and $200 million credit facilities and for general partnership purposes.

In July 2011, the Operating Partnership issued $300 million of 4.65 percent Senior Notes and $300 million of 6.10 percent Senior Notes (the "2022 and 2042 Senior Notes"), due February 2022 and February 2042, respectively. The net proceeds of $595 million from the 2022 and 2042 Senior Notes were used to pay down outstanding borrowings under the prior credit facilities, which were used to fund the acquisitions of a controlling financial interest in Inland and the Texon crude oil acquisition and marketing business, and for general partnership purposes.

Promissory Note, Affiliated Companies

During the fourth quarter 2011, the Partnership repaid in full a $100 million subordinated variable-rate promissory note to Sunoco. The note was entered into in July 2010 to fund a portion of the purchase price of the July 2010 acquisition of the Partnership's butane blending business and was due in May 2013.

Debt Guarantee

The Partnership currently serves as guarantor of the senior notes and of any obligations under the $1.50 billion Credit Facility. This guarantee is full and unconditional. See Note 20 for supplemental condensed consolidating financial information.

11. Commitments and Contingent Liabilities

Total rental expense for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011 amounted to $12, $3, $8, and $10 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, 2013 is as follows:



Year Ended December 31,	(in millions)
2014	$	6
2015	6
2016	4
2017	3
2018	—
Thereafter	1
Total	$	20

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, 2013 and 2012, there were accrued liabilities for environmental remediation in the consolidated balance sheets of $5 and $3 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, $1, $6, and $5 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, 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, 2013 and 2012.

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, 2013, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled $3 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, 2013. 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, 2013. 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, 2013.

12. Equity Offerings

In July 2011, the Partnership issued 3.9 million Class A units to Sunoco in connection with the acquisition of the Eagle Point tank farm and related assets. These deferred distribution units represented a new class of units that were converted to common units in July 2012. Prior to their conversion, the Class A units participated in the allocation of net income on a pro-rata basis with the common units. In accordance with applicable accounting guidance, the Partnership recorded the Class A units at $20 million, the difference between Sunoco's historical carrying value of the assets acquired and the cash paid by the Partnership. In connection with this transaction, the general partner contributed $2 million to the Partnership to maintain its two percent general partner interest.

Subsequent to its filing of the 2013 Form 10-K in February 2014, the Partnership filed a registration statement with the intention of establishing an at-the-market equity offering program. The program is subject to regulatory approval and would allow the Partnership to issue common units directly to the public and raise capital in a timely and efficient manner to support its growth capital program, while supporting the Partnership's investment-grade credit ratings.

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 $0.1667 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:



	Total Quarterly Distribution Target Amount	Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	General Partner			Unitholders
Minimum Quarterly Distribution	$0.1500	2	%		98%
First Target Distribution	up to $0.1667	2	%		98%
Second Target Distribution	above $0.1667 up to $0.1917	15	%	⁽¹⁾	85%
Third Target Distribution	above $0.1917 up to $0.5275	37	%	⁽¹⁾	63%
Thereafter	above $0.5275	50	%	⁽¹⁾	50%


⁽¹⁾	Includes two percent general partner interest.

Distributions paid by the Partnership 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)
Successor
November 14, 2013	$	0.6300	$	2.5200	$	65	$	32
August 14, 2013	$	0.6000	$	2.4000	$	62	$	29
May 15, 2013	$	0.5725	$	2.2900	$	59	$	26
February 14, 2013	$	0.5450	$	2.1800	$	57	$	23
November 14, 2012	$	0.5175	$	2.0700	$	54	$	20


Predecessor
August 14, 2012	$	0.4700	$	1.8800	$	49	$	17
May 15, 2012	$	0.4275	$	1.7100	$	43	$	14
February 14, 2012	$	0.4200	$	1.6800	$	41	$	14
November 14, 2011	$	0.4133	$	1.6532	$	41	$	13
August 12, 2011	$	0.4050	$	1.6200	$	40	$	13
May 13, 2011	$	0.3983	$	1.5932	$	40	$	12
February 14, 2011	$	0.3933	$	1.5732	$	39	$	12

On January 29, 2014, the Partnership declared a cash distribution of $0.6625 per unit ($2.65 per unit annualized) on its outstanding common units, representing the distribution for the quarter ended December 31, 2013. The $104 million distribution, including $35 million to the general partner, was paid on February 14, 2014 to unitholders of record at the close of business on February 10, 2014.

14. Management Incentive Plan

Sunoco Partners LLC, the general partner of the Partnership, has adopted the Sunoco Partners LLC Long-Term Incentive Plan ("LTIP") for employees and directors of the general partner who perform services for the Partnership. The 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. The LTIP currently permits the grant of restricted units and unit options covering an additional 0.6 million common units.

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 LTIP to employees and directors containing such terms as the Compensation Committee shall determine. 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 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. Restricted unit awards granted prior to October 4, 2012 were primarily performance-based. These awards are 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 can cause the actual amount of units that ultimately vest to range between 0 to 200 percent of the original units granted. These awards generally vest over a three-year period. Restricted unit awards granted subsequent to

October 5, 2012 are time-vested grants, the vesting of which is conditioned solely upon continued employment or service as of the applicable vesting date. Such awards generally vest over a five-year period.

The following table summarizes information regarding restricted unit award activity for the periods presented:



	Number of Units		Weighted Average Grant Date Fair Value
Predecessor
Granted, non-vested and outstanding, December 31, 2010	444,093		$	22.59
Granted ⁽¹⁾	189,714		$	31.13
Performance factor adjustment	184,113		$	19.88
Vested	(413,934	)	$	20.05
Cancelled/forfeited	(23,010	)	$	27.66
Granted, non-vested and outstanding, December 31, 2011	380,976		$	27.86
Granted ⁽¹⁾	192,459		$	35.92
Performance factor adjustment	137,941		$	25.24
Vested	(47,916	)	$	30.16
Cancelled/forfeited	(20,409	)	$	31.47
Granted, non-vested and outstanding, October 4, 2012	643,051		$	29.42


Successor
Granted, non-vested and outstanding, October 5, 2012	643,051		$	29.42
Granted	128,573		$	50.55
Performance factor adjustment	12,554		$	31.51
Vested ⁽²⁾	(356,568	)	$	25.67
Cancelled/forfeited	—		$	—
Granted, non-vested and outstanding, December 31, 2012	427,610		$	38.96
Granted	429,123		$	60.01
Performance factor adjustment	101,310		$	31.51
Vested	(281,834	)	$	36.66
Cancelled/forfeited	(36,628	)	$	48.38
Granted, non-vested and outstanding, December 31, 2013	639,581		$	52.37


⁽¹⁾	Of the total number of restricted units granted, the portion that represents units that are subject to performance factors may ultimately be issued at 0 to 200 percent of the original grant, based on the Partnership's achievement of performance goals for total shareholder return and cash distributions relative to a selected peer group of competitors.


⁽²⁾	Relates primarily to awards that vested as a result of the acquisition of the general partner by ETP (Note 1). The unit-based compensation expense attributable to these awards that was recognized during the period from October 5, 2012 to December 31, 2012 was not material as the majority of such awards were scheduled to vest in December 2012.

The total fair value of restricted unit awards vested for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011 was $21, $18, $2, and $18 million, respectively. As of December 31, 2013, estimated compensation cost related to non-vested awards not yet recognized was $21 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years. The number of restricted stock units outstanding and the total compensation cost related to non-vested awards not yet recognized reflects the Partnership's estimates of performance factors for certain restricted unit awards.

The estimated fair value of restricted units under the LTIP is determined based upon the nature of the award. For performance-based awards, the fair value of the restricted units subject to the cash distribution performance targets was determined using the grant date market price of the Partnership's common units, subject to a performance factor adjustment over the course of the vesting. For performance-based awards subject to market-based performance targets, the fair value was determined using a Monte Carlo simulation. 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.

The following table summarizes the fair value assumptions associated with the performance-based awards issued during the periods presented. The awards granted subsequent to October 5, 2012 were not performance based awards.



	Predecessor
	Period from January 1, 2012 to October 4, 2012			Year Ended December 31, 2011
Expected unit-price volatility	22.8		%	24.6		%
Distribution yield	4.6		%	5.4		%
Risk-free interest rate	0.3		%	1.0		%
Weighted average fair value of performance units granted during the year	$	34.94		$	31.51

Expected unit-price volatility was based on the daily historical volatility of the Partnership's common units, generally for the three years prior to the grant date. The distribution yield represents the Partnership's annualized distribution yield on the average closing price of the Partnership's common units 30 days prior to the date of grant. The risk-free interest rate was based on the zero-coupon U.S. Treasury bond, with a term equal to the remaining contractual term of the restricted unit awards.

Based on the unit grants and performance factor adjustments outlined in the table above, the Partnership recognized unit-based compensation expense related to the LTIP within selling, general and administrative expenses in the consolidated statements of comprehensive income of $14, $2, $6, and $6 million for the year ended December 31, 2013, the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively. The tandem DERs associated with the restricted unit grants are recognized as a reduction of equity when earned.

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 interest rates. In order to manage such exposure, the Partnership's policy is (i) to only purchase crude oil, refined products and NGLs 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) not to 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. Pursuant to the Partnership's approved risk management policy, derivative contracts may be used to hedge or reduce exposure to price risk associated with acquired inventory or forecasted physical transactions.

Price Risk Management

The Partnership is exposed to risks associated with changes in the market price of crude oil, refined products and NGLs as a result of the forecasted purchase or sale of these products. These risks are primarily associated with price volatility related to preexisting 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. The physical contracts related to the Partnership's crude oil, refined products and NGL businesses that qualify as derivatives have been designated as normal purchases and sales and are accounted for using accrual accounting under GAAP. The Partnership accounts for derivatives that do not qualify as normal purchases and sales at fair value. The Partnership currently does not utilize derivative instruments to manage its exposure to prices related to crude oil purchase and sale activities.

The Partnership utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. 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. Since the first quarter 2013, the Partnership has not designated any of its derivative contracts 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 during the current period. For refined products derivative contracts that were designated and qualified as cash flow hedges prior to the first quarter 2013, the portion of the gain or loss on the derivative contract that was effective in offsetting the variable cash flows associated with the hedged forecasted transaction was reported as a component of other comprehensive income (loss) and reclassified into earnings in the same period or periods during which the hedged transaction affected earnings. The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), was recognized in earnings during the current period. The amount of hedge ineffectiveness on derivative contracts was not material during 2013, 2012 or 2011. All realized gains and losses associated with refined products derivative contracts are recorded in

earnings in the same line item associated with the forecasted transaction, either sales and other operating revenue or cost of products sold.

The Partnership had open derivative positions on 1.6 million barrels of refined products and NGLs at December 31, 2013 and 1.5 million barrels of refined products at December 31, 2012. The derivatives outstanding at December 31, 2013 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). As of December 31, 2013 and 2012, the fair values of the Partnership's derivative assets and liabilities were:



	Successor
	December 31,
	2013			2012
	(in millions)
Derivative assets	$	1		$	4
Derivative liabilities	(3		)	(7		)
	$	(2	)	$	(3	)

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

The Partnership's derivative positions are comprised primarily of commodity contracts. The following table sets forth the impact of derivatives on the Partnership's results of operations for the periods presented:



	Gains (Losses) Recognized in Other Comprehensive Income (Loss)			Gains (Losses) Recognized in Earnings			Location of Gains (Losses) Recognized in Earnings
(in millions)
Successor
Year Ended December 31, 2013
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	—		$	(1	)	Sales and other operating revenue
Commodity contracts	—			—			Cost of products sold
	$	—		$	(1	)
Derivatives not designated as hedging instruments:
Commodity contracts				$	(7	)	Sales and other operating revenue
Commodity contracts				1			Cost of products sold
				$	(6	)
Period from Acquisition (October 5, 2012) to December 31, 2012 ⁽¹⁾
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	—		$	(1	)	Sales and other operating revenue
Commodity contracts	—			—			Cost of products sold
	$	—		$	(1	)
Derivatives not designated as hedging instruments:
Commodity contracts				$	—		Sales and other operating revenue
Commodity contracts				12			Cost of products sold
				$	12


Predecessor
Period from January 1, 2012 to October 4, 2012
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	(21	)	$	(3	)	Sales and other operating revenue
Commodity contracts	—			1			Cost of products sold
	$	(21	)	$	(2	)
Derivatives not designated as hedging instruments:
Commodity contracts				$	(7	)	Sales and other operating revenue
Commodity contracts				(4		)	Cost of products sold
				$	(11	)
Year Ended December 31, 2011
Derivatives designated as cash flow hedging instruments:
Commodity contracts	$	4		$	(1	)	Sales and other operating revenue
Commodity contracts	—			2			Cost of products sold
	$	4		$	1
Derivatives not designated as hedging instruments:
Commodity contracts				$	6		Sales and other operating revenue
Commodity contracts				(1		)	Cost of products sold
				$	5

⁽¹⁾

The Partnership had deferred hedging losses of approximately $17 million in the accumulated other comprehensive loss component of equity prior to the acquisition of the general partner by ETP. These deferred losses were eliminated in connection with the adjustment of the Partnership's assets and liabilities to fair value (Note 1). In addition, the Partnership did not re-designate its cash flow hedging derivatives which were open on the acquisition date. The Partnership's earnings for the period from October 5, 2012 to December 31, 2012 included approximately $12 million of hedging gains resulting from the elimination of the deferred hedging losses of such positions and the non-hedge designation subsequent to the acquisition date.

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 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. At December 31, 2013 and 2012, the Partnership did not hold any over-the-counter derivatives.

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 debt. At December 31, 2013, the Partnership had $235 million of consolidated variable-rate borrowings under its revolving credit facilities.

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, 2013 was $2.17 billion, compared to the carrying amount of $2.27 billion. The estimated aggregate fair value of the senior notes at December 31, 2012 was $1.64 billion, compared to the carrying amount of $1.59 billion.

For further information regarding the Partnership's fair value measurements, see Notes 1, 2 and 15.

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 and guarantees.

In 2013 and 2012, approximately 15 and 18 percent of the Partnership's total revenues, respectively, were derived from crude oil sales to an individual customer. 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, the customer is subject to netting arrangements which allow the Partnership to offset payable activities and mitigate credit exposure.

18. Business Segment Information

The Partnership operates in more than 30 states throughout the United States and in four principal business segments: Crude Oil Pipelines, Crude Oil Acquisition and Marketing, Terminal Facilities and Refined Products Pipelines.

•

The Crude Oil Pipelines segment transports crude oil principally in Oklahoma and Texas. The segment consists of approximately 4,900 miles of crude oil trunk pipelines and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines. The pipelines receive fees for transporting crude oil to and from trading hubs, other pipelines and refineries in the southwest and midwest United States. The segment also includes a joint venture interest in a crude oil pipeline company in Texas, which is expected to be operational in 2015.


•	The Crude Oil Acquisition and Marketing segment gathers, purchases, markets and sells crude oil principally in the mid-continent United States. The segment consists of approximately 300 crude oil transport trucks and approximately 130 crude oil truck unloading facilities.


•	The Terminal Facilities segment consists of 39 active refined products terminals with an aggregate storage capacity of 8 million barrels, which provide storage, terminalling, blending and other ancillary services and are primarily sourced by the Refined Products Pipelines; the Nederland Terminal, a 22 million barrel marine crude oil terminal on the Texas

Gulf Coast; a 2 million barrel refined product and NGL terminal near Philadelphia, Pennsylvania; one inland and two marine crude oil terminals with a combined capacity of 3 million barrels, and related pipelines, which serve the Philadelphia refinery; the Eagle Point Terminal, a 5 million barrel refined products and crude oil terminal and dock facility; the 5 million barrel Marcus Hook, Pennsylvania refined products and NGL facility; and a 1 million barrel liquefied petroleum gas terminal near Detroit, Michigan. The terminals receive fees for the terminalling, blending and other services provided.

•

The Refined Products Pipelines segment consists of approximately 2,500 miles of refined products and NGL pipelines, and joint venture interests in four refined products pipelines in selected areas of the United States. The pipelines receive fees for transporting products from refineries to markets in the northeast, midwest and southwest United States, and from processing and fractionating areas to the Sarnia, Ontario petrochemical market.

During the fourth quarter 2012, the Partnership changed its definition of Adjusted EBITDA and Distributable Cash Flow to conform to the presentation utilized by its general partner. The Partnership also changed its measure of segment profit from operating income to the revised presentation of Adjusted EBITDA. This change did not impact the Partnership's reportable segments. Prior period amounts have been recast to conform to current presentation.

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:



	Successor						Predecessor
	Year Ended December 31, 2013			Period from Acquisition (October 5, 2012) to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31, 2011
	(in millions)						(in millions)
Sales and other operating revenue ⁽¹⁾
Crude Oil Pipelines	$	495		$	110		$	288		$	319
Crude Oil Acquisition and Marketing	15,518			2,888			9,258			10,163
Terminal Facilities	751			206			406			435
Refined Products Pipelines	130			35			96			130
Intersegment eliminations	(255		)	(50		)	(127		)	(142		)
Total sales and other operating revenue	$	16,639		$	3,189		$	9,921		$	10,905
Depreciation and amortization
Crude Oil Pipelines	$	90		$	22		$	19		$	25
Crude Oil Acquisition and Marketing	49			11			16			10
Terminal Facilities	101			23			28			34
Refined Products Pipelines	25			7			13			17
Total depreciation and amortization	$	265		$	63		$	76		$	86
Impairment charge and related matters ^{(2) (3)}
Crude Oil Acquisition and Marketing	$	—		$	—		$	8		$	—
Terminal Facilities	—			—			(10		)	42
Refined Products Pipelines	—			—			1			—
Total impairment charge and related matters	$	—		$	—		$	(1	)	$	42
Capital expenditures ⁽⁴⁾
Crude Oil Pipelines	$	190		$	65		$	56		$	49
Crude Oil Acquisition and Marketing	25			1			15			15
Terminal Facilities	252			45			138			121
Refined Products Pipelines	533			26			24			23
Corporate	18			2			2			5
Total capital expenditures	$	1,018		$	139		$	235		$	213
Adjusted EBITDA
Crude Oil Pipelines	$	349		$	72		$	203		$	207
Crude Oil Acquisition and Marketing	233			81			158			148
Terminal Facilities	233			52			173			149
Refined Products Pipelines	56			14			57			69
Total Adjusted EBITDA	871			219			591			573
Interest expense, net	(77		)	(14		)	(65		)	(89		)
Depreciation and amortization expense	(265		)	(63		)	(76		)	(86		)
Impairment charge	—			—			(9		)	(31		)
Provision for income taxes	(30		)	(8		)	(24		)	(25		)
Non-cash compensation expense	(14		)	(2		)	(6		)	(6		)
Unrealized losses/(gains) on commodity risk management activities	1			3			(6		)	2
Amortization of excess equity method investment	(2		)	—			—			—
Proportionate share of unconsolidated affiliates' interest, depreciation and provision for income taxes	(20		)	(5		)	(16		)	(16		)
Non-cash accrued liability adjustment	10			—			—			—
Adjustments to commodity hedges resulting from "push-down" accounting	—			12			—			—
Net Income ⁽⁵⁾	474			142			389			322
Net Income attributable to noncontrolling interests	11			3			8			9
Net Income attributable to Sunoco Logistics Partners L.P.	$	463		$	139		$	381		$	313


⁽¹⁾	Sales and other operating revenue for the periods presented includes the following amounts from ETP and its affiliates:



	Successor				Predecessor
	Year Ended December 31, 2013		Period from Acquisition (October 5, 2012) to December 31, 2012		Period from January 1, 2012 to October 4, 2012		Year Ended December 31, 2011
	(in millions)				(in millions)
Crude Oil Pipelines	$	—	$	—	$	—	$	6
Crude Oil Acquisition and Marketing	1,394		139		307		247
Terminal Facilities	139		50		118		115
Refined Products Pipelines	33		11		36		64
Total sales and other operating revenue	$	1,566	$	200	$	461	$	432


⁽²⁾	In the first quarter 2012, the Partnership recognized a non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas. The impairment was recorded as $8 and $1 million within the Crude Oil Acquisition and Marketing and Refined Products Pipelines segments, respectively.

⁽³⁾

In 2011, the Partnership recognized a charge of $42 million for certain crude oil terminal assets which would have been negatively impacted if Sunoco's Philadelphia refinery were permanently idled. The charge included a $31 million non-cash impairment for asset write-downs at the Fort Mifflin Terminal Complex and $11 million for regulatory obligations which would have been incurred if these assets were permanently idled. In the second quarter 2012, the Partnership recognized a $10 million gain on the reversal of certain regulatory obligations. Such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco's joint venture with The Carlyle Group.


⁽⁴⁾	Total capital expenditures in 2013 exclude $60 million for the acquisition of the Marcus Hook Facility. Total capital expenditures in 2011 exclude $396 million for the acquisition of a crude oil and marketing business, a refined products terminal, an interest in the Inland refined products pipeline system and the Eagle Point tank farm.


⁽⁵⁾	Net income includes $20, $5, $14, and $12 million for the year ended December 31, 2013, for the periods from October 5, 2012 to December 31, 2012 and from January 1, 2012 to October 4, 2012, and for the year ended December 31, 2011, respectively, of equity income attributable to the Refined Products Pipelines equity ownership interest in joint ventures.

The following table provides consolidated balance sheet information concerning the Partnership's business segments as of December 31, 2013, 2012 and 2011, respectively:



	Crude Oil Pipelines		Crude Oil Acquisition and Marketing		Terminal Facilities		Refined Products Pipelines		Total
	(in millions)
Successor
As of December 31, 2013
Investment in affiliates	$	3	$	—	$	—	$	122	$	125
Goodwill	$	200	$	545	$	601	$	—	$	1,346
Identifiable assets ⁽¹⁾	$	3,321	$	3,863	$	2,701	$	1,684	$	11,897
As of December 31, 2012
Investment in affiliates	$	—	$	—	$	—	$	118	$	118
Goodwill	$	200	$	545	$	623	$	—	$	1,368
Identifiable assets ⁽²⁾	$	3,167	$	3,495	$	2,402	$	1,198	$	10,361


Predecessor
As of December 31, 2011
Investment in affiliates	$	—	$	—	$	—	$	73	$	73
Goodwill	$	2	$	14	$	53	$	8	$	77
Identifiable assets ⁽³⁾	$	1,055	$	2,469	$	1,053	$	736	$	5,477


⁽¹⁾	Total identifiable assets include the Partnership's unallocated $12 million cash and cash equivalents, $239 million advances to affiliates, $66 million to properties, plants and equipment, net and $11 million of other assets.


⁽²⁾	Total identifiable assets include the Partnership's unallocated $2 million cash and cash equivalents, $56 million advances to affiliates, $40 million to properties, plants and equipment, net and $1 million of other assets.


⁽³⁾	Total identifiable assets include the Partnership's unallocated $2 million cash and cash equivalents, $107 million advances to affiliates, $15 million deferred financing costs, and $40 million to properties, plants and equipment, net.

19. Quarterly Financial Data (Unaudited)

Summarized quarterly financial data is as follows:



	Successor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter ⁽¹⁾
	(in millions, except per unit amounts)
2013
Sales and other operating revenue:
Unaffiliated customers	$	3,098		$	3,948		$	4,120		$	3,907
Affiliates	$	414		$	363		$	408		$	381
Gross profit ⁽²⁾	$	262		$	263		$	205		$	218
Operating income	$	165		$	165		$	104		$	126
Net Income	$	142		$	146		$	81		$	105
Net Income attributable to noncontrolling interests	2			3			3			3
Net Income attributable to Sunoco Logistics Partners L.P.	$	140		$	143		$	78		$	102
Less: General Partner's interest	(27		)	(30		)	(31		)	(36		)
Limited Partners' interest	$	113		$	113		$	47		$	66
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic	$	1.09		$	1.09		$	0.45		$	0.64
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted	$	1.09		$	1.08		$	0.45		$	0.63



	Predecessor									Successor
	First Quarter			Second Quarter			Third Quarter			Period from Acquisition (October 5, 2012) to December 31, 2012
	(in millions, except per unit amounts)									(in millions, except per unit amounts)
2012
Sales and other operating revenue:
Unaffiliated customers	$	3,275		$	3,119		$	3,066		$	2,989
Affiliates	$	126		$	194		$	141		$	200
Gross profit ⁽²⁾	$	176		$	224		$	210		$	256
Operating income ⁽³⁾	$	127		$	179		$	154		$	159
Net Income ^{(4) (5)}	$	97		$	155		$	137		$	142
Net Income attributable to noncontrolling interests	2			3			3			3
Net Income attributable to Sunoco Logistics Partners L.P.	$	95		$	152		$	134		$	139
Less: General Partner's interest	(15		)	(19		)	(21		)	(24		)
Limited Partners' interest	$	80		$	133		$	113		$	115
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—basic	$	0.77		$	1.29		$	1.09		$	1.11
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit—diluted	$	0.77		$	1.28		$	1.09		$	1.10


⁽¹⁾	During the fourth quarter 2013, the Partnership recognized a gain of $10 million on a non-cash accrued liability adjustment.


⁽²⁾	Gross profit equals sales and other operating revenue less cost of products sold and operating expenses.

⁽³⁾

During the first quarter 2013, the Partnership adjusted its presentation of operating income reported in the consolidated statements of comprehensive income to conform to the presentation utilized by ETP. Other income, which is comprised primarily of equity income from the Partnership's unconsolidated joint-venture interests, is presented separately and is no longer included as a component of operating income. These changes did not impact the Partnership's net income. Prior period amounts have been recast to conform to current presentation.

⁽⁴⁾

Net income for the first quarter 2012 includes an $11 million gain for cash payments received for the cancellation of existing throughput and deficiency agreements in connection with the Partnership's sale of refined products terminal and pipeline assets in Big Sandy, Texas, and a $9 million non-cash impairment charge related to a cancelled software project for the crude oil acquisition and marketing business and a refined products pipeline project in Texas.


⁽⁵⁾	Net income for the second quarter 2012 includes a $10 million gain on the reversal of certain regulatory obligations. Such expenses were no longer expected to be incurred as the Philadelphia refinery will continue to operate in connection with Sunoco's joint venture with The Carlyle Group.

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.

Consolidating Statement of Comprehensive Income (Loss)

Year Ended December 31, 2013 (Successor)

(in millions)



	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	15,073		$	—		$	15,073
Affiliates	—		—			1,566			—			1,566
Total Revenues	—		—			16,639			—			16,639
Costs and Expenses
Cost of products sold	—		—			15,574			—			15,574
Operating expenses	—		—			117			—			117
Selling, general and administrative expenses	—		—			123			—			123
Depreciation and amortization expense	—		—			265			—			265
Total Costs and Expenses	—		—			16,079			—			16,079
Operating Income	—		—			560			—			560
Net interest income (cost) to affiliates	—		3			(4		)	—			(1		)
Other interest cost and debt expense, net	—		(96		)	(1		)	—			(97		)
Capitalized interest	—		21			—			—			21
Other income	—		—			21			—			21
Equity in earnings of subsidiaries	463		535			—			(998		)	—
Income (Loss) Before Provision for Income Taxes	463		463			576			(998		)	504
Provision for income taxes	—		—			(30		)	—			(30		)
Net Income (Loss)	463		463			546			(998		)	474
Net Income attributable to noncontrolling interests	—		—			(11		)	—			(11		)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	463	$	463		$	535		$	(998	)	$	463

Net Income (Loss)	$	463	$	463		$	546		$	(998	)	$	474
Gain (loss) on cash flow hedges	—		—			—			—			—
Other Comprehensive Income (Loss)	—		—			—			—			—
Comprehensive Income (Loss)	463		463			546			(998		)	474
Less: Comprehensive income attributable to noncontrolling interests	—		—			(11		)	—			(11		)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	463	$	463		$	535		$	(998	)	$	463

Consolidating Statement of Comprehensive Income (Loss)

Period from October 5, 2012 to December 31, 2012 (Successor)

(in millions)



	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	2,989		$	—		$	2,989
Affiliates	—		—			200			—			200
Total Revenues	—		—			3,189			—			3,189
Costs and Expenses
Cost of products sold	—		—			2,885			—			2,885
Operating expenses	—		—			48			—			48
Selling, general and administrative expenses	—		—			34			—			34
Depreciation and amortization expense	—		—			63			—			63
Total Costs and Expenses	—		—			3,030			—			3,030
Operating Income	—		—			159			—			159
Net interest income (cost) to affiliates	—		1			(1		)	—			—
Other interest cost and debt expense, net	—		(18		)	—			—			(18		)
Capitalized interest	—		4			—			—			4
Other income	—		—			5			—			5
Equity in earnings of subsidiaries	139		152			—			(291		)	—
Income (Loss) Before Provision for Income Taxes	139		139			163			(291		)	150
Provision for income taxes	—		—			(8		)	—			(8		)
Net Income (Loss)	139		139			155			(291		)	142
Net Income attributable to noncontrolling interests	—		—			(3		)	—			(3		)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	139	$	139		$	152		$	(291	)	$	139

Net Income (Loss)	$	139	$	139		$	155		$	(291	)	$	142
Gain (loss) on cash flow hedges	—		—			—			—			—
Other Comprehensive Income (Loss)	—		—			—			—			—
Comprehensive Income (Loss)	139		139			155			(291		)	142
Less: Comprehensive income attributable to noncontrolling interests	—		—			(3		)	—			(3		)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	139	$	139		$	152		$	(291	)	$	139

Consolidating Statement of Comprehensive Income (Loss)

Period from January 1, 2012 to October 4, 2012 (Predecessor)

(in millions)



	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	9,460		$	—		$	9,460
Affiliates	—		—			461			—			461
Gain on divestment and related matters	—		—			11			—			11
Total Revenues	—		—			9,932			—			9,932
Costs and Expenses
Cost of products sold	—		—			9,214			—			9,214
Operating expenses	—		—			97			—			97
Selling, general and administrative expenses	—		—			86			—			86
Depreciation and amortization expense	—		—			76			—			76
Impairment charge and related matters	—		—			(1		)	—			(1		)
Total Costs and Expenses	—		—			9,472			—			9,472
Operating Income	—		—			460			—			460
Other interest cost and debt expense, net	—		(70		)	(3		)	—			(73		)
Capitalized interest	—		8			—			—			8
Other income	—		—			18			—			18
Equity in earnings of subsidiaries	381		443			—			(824		)	—
Income (Loss) Before Provision for Income Taxes	381		381			475			(824		)	413
Provision for income taxes	—		—			(24		)	—			(24		)
Net Income (Loss)	381		381			451			(824		)	389
Net Income attributable to noncontrolling interests	—		—			(8		)	—			(8		)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	381	$	381		$	443		$	(824	)	$	381

Net Income (Loss)	$	381	$	381		$	451		$	(824	)	$	389
Loss on cash flow hedges	—		—			(21		)	—			(21		)
Other Comprehensive Income (Loss)	—		—			(21		)	—			(21		)
Comprehensive Income (Loss)	381		381			430			(824		)	368
Less: Comprehensive income attributable to noncontrolling interests	—		—			(8		)	—			(8		)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	381	$	381		$	422		$	(824	)	$	360

Consolidating Statement of Comprehensive Income (Loss)

Year Ended December 31, 2011 (Predecessor)

(in millions)



	Parent Guarantor		Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Revenues
Sales and other operating revenue:
Unaffiliated customers	$	—	$	—		$	10,473		$	—		$	10,473
Affiliates	—		—			432			—			432
Total Revenues	—		—			10,905			—			10,905
Costs and Expenses
Cost of products sold	—		—			10,153			—			10,153
Operating expenses	—		—			111			—			111
Selling, general and administrative expenses	—		—			90			—			90
Depreciation and amortization expense	—		—			86			—			86
Impairment charge	—		—			42			—			42
Total Costs and Expenses	—		—			10,482			—			10,482
Operating Income	—		—			423			—			423
Net interest income (cost) to affiliates	—		—			(3		)	—			(3		)
Other interest cost and debt expense, net	—		(93		)	—			—			(93		)
Capitalized interest	—		7			—			—			7
Other income	—		—			13			—			13
Equity in earnings of subsidiaries	313		399			—			(712		)	—
Income (Loss) Before Provision for Income Taxes	313		313			433			(712		)	347
Provision for income taxes	—		—			(25		)	—			(25		)
Net Income (Loss)	313		313			408			(712		)	322
Net Income attributable to noncontrolling interests	—		—			(9		)	—			(9		)
Net Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	313	$	313		$	399		$	(712	)	$	313

Net Income (Loss)	$	313	$	313		$	408		$	(712	)	$	322
Gain on cash flow hedges	—		—			4			—			4
Other Comprehensive Income (Loss)	—		—			4			—			4
Comprehensive Income (Loss)	313		313			412			(712		)	326
Less: Comprehensive income attributable to noncontrolling interests	—		—			(9		)	—			(9		)
Comprehensive Income (Loss) Attributable to Sunoco Logistics Partners L.P.	$	313	$	313		$	403		$	(712	)	$	317

Consolidating Balance Sheet

December 31, 2013 (Successor)

(in millions)



	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	12	$	27		$	—		$	39
Advances to affiliated companies	217		79		(57		)	—			239
Accounts receivable, affiliated companies	—		—		11			—			11
Accounts receivable, net	—		—		2,184			—			2,184
Inventories	—		—		600			—			600
Total Current Assets	217		91		2,765			—			3,073
Properties, plants and equipment, net	—		—		6,519			—			6,519
Investment in affiliates	5,988		8,399		125			(14,387		)	125
Goodwill	—		—		1,346			—			1,346
Intangible assets, net	—		—		794			—			794
Other assets	—		10		30			—			40
Total Assets	$	6,205	$	8,500	$	11,579		$	(14,387	)	$	11,897
Liabilities and Equity
Accounts payable	$	—	$	—	$	2,451		$	—		$	2,451
Accounts payable, affiliated companies	—		—		17			—			17
Accrued liabilities	1		44		152			—			197
Accrued taxes payable	—		—		71			—			71
Total Current Liabilities	1		44		2,691			—			2,736
Long-term debt	—		2,468		35			—			2,503
Other deferred credits and liabilities	—		—		80			—			80
Deferred income taxes	—		—		253			—			253
Total Liabilities	1		2,512		3,059			—			5,572
Equity
Sunoco Logistics Partners L.P. equity	6,204		5,988		8,399			(14,387		)	6,204
Noncontrolling interests	—		—		121			—			121
Total Equity	6,204		5,988		8,520			(14,387		)	6,325
Total Liabilities and Equity	$	6,205	$	8,500	$	11,579		$	(14,387	)	$	11,897

Consolidating Balance Sheet

December 31, 2012 (Successor)

(in millions)



	Parent Guarantor		Subsidiary Issuer		Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Assets
Cash and cash equivalents	$	—	$	2	$	1		$	—		$	3
Advances to affiliated companies	25		48		(17		)	—			56
Accounts receivable, affiliated companies	—		—		19			—			19
Accounts receivable, net	—		—		1,834			—			1,834
Inventories	—		—		478			—			478
Total Current Assets	25		50		2,315			—			2,390
Properties, plants and equipment, net	—		—		5,623			—			5,623
Investment in affiliates	6,048		7,714		118			(13,762		)	118
Goodwill	—		—		1,368			—			1,368
Intangible assets, net	—		—		843			—			843
Other assets	—		—		19			—			19
Total Assets	$	6,073	$	7,764	$	10,286		$	(13,762	)	$	10,361
Liabilities and Equity
Accounts payable	$	—	$	—	$	1,912		$	—		$	1,912
Accounts payable, affiliated companies	—		—		12			—			12
Accrued liabilities	1		30		116			—			147
Accrued taxes payable	—		—		60			—			60
Total Current Liabilities	1		30		2,100			—			2,131
Long-term debt	—		1,686		46			—			1,732
Other deferred credits and liabilities	—		—		60			—			60
Deferred income taxes	—		—		243			—			243
Total Liabilities	1		1,716		2,449			—			4,166
Equity
Sunoco Logistics Partners L.P. equity	6,072		6,048		7,714			(13,762		)	6,072
Noncontrolling interests	—		—		123			—			123
Total Equity	6,072		6,048		7,837			(13,762		)	6,195
Total Liabilities and Equity	$	6,073	$	7,764	$	10,286		$	(13,762	)	$	10,361

Consolidating Statement of Cash Flows

Year Ended December 31, 2013 (Successor)

(in millions)



	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	463		$	446		$	838		$	(998	)	$	749
Cash Flows from Investing Activities:
Capital expenditures	—			—			(897		)	—			(897		)
Acquisitions	—			—			(60		)	—			(60		)
Intercompany	95			(1,177		)	84			998			—
Net cash provided by (used in) investing activities	95			(1,177		)	(873		)	998			(957		)
Cash Flows from Financing Activities:
Distributions paid to limited and general partners	(353		)	—			—			—			(353		)
Distributions paid to noncontrolling interests	(13		)	—			—			—			(13		)
Payments of statutory withholding on net issuance of limited partner units under LTIP	—			—			(3		)	—			(3		)
Repayments under credit facilities	—			(119		)	—			—			(119		)
Borrowings under credit facilities	—			200			15			—			215
Net proceeds from issuance of long-term debt	—			691			—			—			691
Advances to affiliated companies, net	(192		)	(31		)	40			—			(183		)
Contributions attributable to acquisition from affiliate	—			—			9			—			9
Net cash provided by (used in) financing activities	(558		)	741			61			—			244
Net change in cash and cash equivalents	—			10			26			—			36
Cash and cash equivalents at beginning of period	—			2			1			—			3
Cash and cash equivalents at end of period	$	—		$	12		$	27		$	—		$	39

Consolidating Statement of Cash Flows

Period from October 5, 2012 to December 31, 2012 (Successor)

(in millions)



	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	140		$	162		$	270		$	(292	)	$	280
Cash Flows from Investing Activities:
Capital expenditures	—			—			(139		)	—			(139		)
Intercompany	(35		)	(37		)	(220		)	292			—
Net cash provided by (used in) investing activities	(35		)	(37		)	(359		)	292			(139		)
Cash Flows from Financing Activities:
Distributions paid to limited and general partners	(74		)	—			—			—			(74		)
Distributions paid to noncontrolling interests	(2		)	—			—			—			(2		)
Payments of statutory withholding on net issuance of limited partner units under LTIP	—			—			(7		)	—			(7		)
Repayments under credit facilities	—			(233		)	—			—			(233		)
Borrowings under credit facilities	—			182			11			—			193
Advances to affiliated companies, net	(28		)	(74		)	85			—			(17		)
Net cash used in financing activities	(104		)	(125		)	89			—			(140		)
Net change in cash and cash equivalents	1			—			—			—			1
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	1		$	2		$	—		$	—		$	3

100

Consolidating Statement of Cash Flows

Period from January 1, 2012 to October 4, 2012 (Predecessor)

(in millions)



	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	381		$	359		$	495		$	(824	)	$	411
Cash Flows from Investing Activities:
Capital expenditures	—			—			(235		)	—			(235		)
Proceeds from divestments and related matters	—			—			11			—			11
Intercompany	(290		)	(279		)	(255		)	824			—
Net cash provided by (used in) investing activities	(290		)	(279		)	(479		)	824			(224		)
Cash Flows from Financing Activities:
Distributions paid to limited and general partners	(178		)	—			—			—			(178		)
Distributions paid to noncontrolling interests	(5		)	—			—			—			(5		)
Payments of statutory withholding on net issuance of limited partner units under LTIP	—			—			(5		)	—			(5		)
Repayments under credit facilities	—			(322		)	—			—			(322		)
Borrowings under credit facilities	—			418			83			—			501
Repayments of senior notes	—			(250		)	—			—			(250		)
Advances to affiliated companies, net	92			74			(97		)	—			69
Net cash provided by (used in) financing activities	(91		)	(80		)	(19		)	—			(190		)
Net change in cash and cash equivalents	—			—			(3		)	—			(3		)
Cash and cash equivalents at beginning of period	—			2			3			—			5
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

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Consolidating Statement of Cash Flows

Year Ended December 31, 2011 (Predecessor)

(in millions)



	Parent Guarantor			Subsidiary Issuer			Non-Guarantor Subsidiaries			Consolidating Adjustments			Total
Net Cash Flows from Operating Activities	$	313		$	322		$	508		$	(713	)	$	430
Cash Flows from Investing Activities:
Capital expenditures	—			—			(213		)	—			(213		)
Acquisitions	—			—			(396		)	—			(396		)
Intercompany	(35		)	(786		)	108			713			—
Net cash provided by (used in) investing activities	(35		)	(786		)	(501		)	713			(609		)
Cash Flows from Financing Activities:
Distributions paid to limited and general partners	(210		)	—			—			—			(210		)
Distributions paid to noncontrolling interests	(8		)	—			—			—			(8		)
Contributions from general partner	2			—			—			—			2
Payments of statutory withholding on net issuance of limited partner units under LTIP	—			—			(3		)	—			(3		)
Repayments under credit facilities	—			(560		)	—			—			(560		)
Borrowings under credit facilities	—			529			—			—			529
Net proceeds from issuance of long-term debt	—			595			—			—			595
Promissory note from affiliate	—			(100		)	—			—			(100		)
Advances to affiliated companies, net	(62		)	—			(1		)	—			(63		)
Net cash provided by (used in) financing activities	(278		)	464			(4		)	—			182
Net change in cash and cash equivalents	—			—			3			—			3
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	—		$	2		$	3		$	—		$	5

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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 of Sunoco Partners LLC (the Partnership's general partner), as appropriate, to allow timely decisions regarding required disclosure.

As of December 31, 2013, 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), 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 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, 2013 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.

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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. Prior to October 5, 2012, our general partner was a wholly-owned indirect subsidiary of Sunoco, Inc., a Pennsylvania corporation (“Sunoco”). On October 5, 2012, Sunoco merged with certain affiliates of Energy Transfer Partners, L.P., a Delaware limited partnership (“ETP”), and is now a wholly-owned, indirect subsidiary of ETP and its affiliates (such transaction, the “Merger”). In connection with the Merger, Sunoco transferred its membership interests in our general partner to ETP. Subsequent to such transfer, ETE Common Holdings, LLC, a Delaware limited liability company (“ETE Holdings”), became a member of our general partner. As a result, ETP owns a 99.9% equity interest in our general partner, and the remaining 0.1% equity interest is owned by 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 of Directors”) shall consist of between three and twelve persons, at least three of whom are required to qualify as independent directors. As of December 31, 2013, the Board of Directors consisted of eight 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.

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 refined products and crude oil operations or finance, and a history of service in senior leadership positions.

The Board of Directors held six (4 regular and 2 special) meetings during 2013. The Board of Directors has established standing committees to consider designated matters. The standing committees of the Board of Directors 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 of Directors has elected to have a standing compensation committee. The Board of Directors has adopted governance guidelines for the Board of Directors and charters for each of the Audit, Compensation, and Conflicts Committees.

Audit Committee

The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board of Directors 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 of Directors has determined that based on relevant experience, Audit Committee member Basil Leon Bray qualified as an audit committee financial expert during 2013. 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 to 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 of Directors relating to our audited financial statements. The Audit Committee periodically

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recommends to the Board of Directors any changes or modifications to its charter that may be required or desired. The Audit Committee has received 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 that 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 held six (5 regular and 1 special) meetings during 2013.

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 performance standards or other restrictions pertaining to the vesting of any such awards. The current members of the Compensation Committee are: Scott A. Angelle (Chairman), Steven R. Anderson, Basil Leon Bray, Michael J. Hennigan, and Marshall S. (Mackie) McCrea, III. Since Mr. Hennigan is also an officer of our general partner, and since Mr. McCrea is President, Chief Operating Officer and Director of ETP’s 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 (“LTIP”)) to executive officers of the general partner. Mr. Hennigan also recuses himself from Compensation Committee decisions relating to his own compensation. The Compensation Committee met four times during 2013.

Conflicts Committee

Our partnership agreement provides that the Board of Directors may, from time to time, appoint members of the Board of Directors to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors 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 its Board of Directors of any duties they may owe to the members of our general partner or our unitholders. The members of the Conflicts Committee consist of those directors of our general partner who are not also executive officers of our general partner or its parent. The current members of the Conflicts Committee are: Steven R. Anderson (Chairman), Scott A. Angelle and Basil Leon Bray. The Conflicts Committee met four times during 2013.

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”).

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 of Directors, 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, 1818 Market Street, Suite 1500, Philadelphia, PA 19103-3615. 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.

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Communications addressed to the Board of Directors generally will be forwarded either to the appropriate committee chairperson or to all directors. Certain concerns communicated to the Board of Directors 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 of Directors, may direct that certain concerns be presented to the Audit Committee, or to the full Board of Directors, or that such concerns otherwise receive special treatment, including retention of external counsel or other advisors. No material actions were taken by the Board of Directors because of communications from unitholders or others received during 2013.

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 of Directors.

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
Steven R. Anderson	64	Director
Scott A. Angelle	52	Director
Basil Leon Bray	69	Director
Michael J. Hennigan	54	Director, President and Chief Executive Officer
Thomas P. Mason	57	Director
Marshall S. ("Mackie") McCrea, III	54	Director (Chairman)
Martin Salinas, Jr.	42	Director and Chief Financial Officer
Jamie Welch	47	Director
Kurt A. Lauterbach	58	Senior Vice President, Lease Acquisitions
David R. Chalson	62	Senior Vice President, Operations
Michael W. Slough	57	Senior Vice President, Engineering, Construction & Procurement
Kathleen Shea-Ballay	48	Senior Vice President, General Counsel and Secretary
Peter J. Gvazdauskas	35	Vice President, Finance and Treasurer
Meghan Zaffarese	38	Vice President, Chief Human Resources Officer
Michael D. Galtman	39	Controller and Chief Accounting Officer

Set forth below is biographical information regarding the foregoing officers and directors of our general partner:

Mr. Anderson was elected to the Board of Directors in October 2012. Mr. Anderson began his career in the energy business more than 40 years ago 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 board of directors of the St. John Health System in Tulsa, Oklahoma, as well as various other community and civic organizations.

Mr. Angelle was elected to the Board of Directors 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.

Mr. Bray was elected to the Board of Directors 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. Hennigan was elected to the Board of Directors 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

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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: 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. Mason was elected to the Board of Directors in October 2012. Mr. Mason has served as the Senior Vice President, General Counsel and Secretary of ETP’s general partner since April 2012, served as the Vice President, General Counsel and Secretary of ETP’s general partner since June 2008 and served 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. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years.

Mr. McCrea was elected as Chairman of the Board of Directors in October 2012. He has been a director of ETP’s general partner since December 23, 2009. He is the President and Chief Operating Officer of ETP’s general partner, and has served in that capacity since June 2008. Prior to that, he served as President, Midstream of ETP’s general partner from March 2007 to June 2008. Mr. McCrea also serves on the Board of Directors of the general partner of Energy Transfer Equity, L.P. (“ETE”). Mr. McCrea has extensive project development and operational experience, and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.

Mr. Salinas was elected to the Board of Directors in October 2012, and was elected contemporaneously as the Chief Financial Officer of our general partner. Mr. Salinas has served as Chief Financial Officer of ETP’s general partner since June 2008. Prior to that, he served as Controller and Treasurer of ETP’s general partner from September 2004 to June 2008. Prior to joining ETP, Mr. Salinas was a Senior Audit Manager with KPMG in San Antonio, Texas from September 2002.

Mr. Welch was elected to the Board of Directors in June 2013. He was also elected to the boards of directors of both ETE and ETP in June 2013. Mr. Welch is the Group Chief Financial Officer and Head of Business Developments for the Energy Transfer family. Before joining ETE, Mr. Welch was Head of the EMEA Investment Banking Department and Head of the Global Energy Group at Credit Suisse. He was also a member of the IBD Global Management Committee and the EMEA Operating Committee. Mr. Welch joined Credit Suisse First Boston in 1997 from Lehman Brothers Inc. in New York, where he was a Senior Vice President in the global utilities & project finance group. Prior to that he was an attorney with Milbank, Tweed, Hadley & McCloy (New York) and a barrister and solicitor with Minter Ellison in Melbourne, Australia.

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. 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.

Mr. Gvazdauskas was elected Vice President, Finance and Treasurer in 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; from December 2007 to May 2008, he was Manager of Special Projects at Sunoco; and from November 2005 to November 2007, he was Controller of SunCoke Energy, Inc.

Mr. Lauterbach was elected Senior Vice President, Lease Acquisitions in January 2013. Prior to that, he was Vice President, Lease Acquisitions, from October 2010 to January 2013. Mr. Lauterbach also served as Manager of Marketing and Trading-Lease Acquisition, from June 2008 through September 2010.

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 from April 2005 until June 2010. Prior to joining Sunoco, Ms. Shea-Ballay was a partner at Pepper Hamilton LLP, a law firm in Philadelphia, Pennsylvania.

Mr. Slough was elected Senior Vice President, Engineering, Construction & Procurement in January 2013. Mr. Slough has 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.

Ms. Zaffarese was elected Vice President, Chief Human Resources Officer in January 2013. Prior to that, she was Director, Human Resources & Administration for the Partnership since March 2011. Prior to that, she was Director, Human Resources, PSG for Sunoco from April 2010 to March 2011 and was Vice President, Executive Development and Corporate Human Resources, ARAMARK Corp. from May 2009 to April 2010.

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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 2013.



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. Except as set forth below with respect to Mr. Salinas, we pay 100% 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 executive officers of our general partner as set forth below. ETP controls our general partner and owns a significant limited partner interest in us. Mr. Salinas is an employee of ETP’s general partner. In addition to rendering services to us, he devoted a majority of his professional time to ETP during 2013. Mr. Salinas participates in employee benefit plans and arrangements sponsored by ETP and its affiliates. The compensation committee of ETP’s general partner sets the components of his compensation, including salary and annual bonus, and we have no control over this compensation determination process. However, our general partner’s Compensation Committee may make equity awards to Mr. Salinas in recognition of his services provided to us. In January 2013, Mr. Salinas received such equity awards, in the form of 8,333 restricted units granted pursuant to the LTIP, vesting at a rate of 20% per year over a five-year period, subject to his continued employment through each specified vesting date. In addition, in December 2013, Mr. Salinas received equity awards, in the form of 6,550 restricted units granted pursuant to the LTIP, vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject to his continued employment through each specified vesting date. These restricted units entitle Mr. Salinas to receive, with respect to each common unit subject to such restricted unit that has not either vested or been forfeited, a distribution equivalent right cash payment promptly following each such distribution by us on our common units to our unitholders.

During 2013, the following individuals, with the exception of Mr. Salinas as described above, 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


•	Martin Salinas, Jr. - Chief Financial Officer


•	Kathleen Shea-Ballay - Senior Vice President, General Counsel and Secretary


•	Kurt A. Lauterbach - Senior Vice President, Lease Acquisitions


•	David R. Chalson - Senior Vice President, Operations

Compensation Philosophy and Objectives

During 2013, as a result of the Merger, we transitioned from our pre-Merger compensation philosophy and objectives to a compensation philosophy and set of objectives similar to those of ETP. In both instances, the philosophy for executive compensation of our general partner (whether pre-Merger or post) was substantially similar based on the premise that a significant portion of each executive’s total compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be competitive in the marketplace for executive talent and abilities. Our general partner seeks a total compensation program that provides for a slightly below the median market annual base compensation rate 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 incentives should be composed of a combination of compensation vehicles to reward both short- and long-term performance. 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 its achievement of the annual

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financial performance objectives and (ii) the annual grant of restricted unit awards under the LTIP, which awards are intended to provide a longer term incentive and retention 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 2013, where doing so was determined to be a cost-effective and an administratively efficient means of providing benefits to its employees, our general partner was a participating employer in certain compensation plans sponsored by ETP or its affiliates. We share in the costs incurred by ETP and its affiliates, as applicable, for the benefits we receive from our participation in these plans. Included in such benefit plans are certain of Sunoco’s plans, in which our general partner was a participating employer prior to the Merger and continues to participate.

During 2013, the compensation for our executive officers, including our NEOs, but excluding Mr. Salinas, was determined by our general partner’s Compensation Committee, which reviews the compensation program and makes changes deemed appropriate and in the best interests of our unitholders and us. The Compensation Committee has authority over all compensation decisions for our NEOs. 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.

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. During 2013, we transitioned from our pre-Merger compensation methodology to a compensation methodology similar to that of ETP.

Because of the timing of the Merger and the transition of ownership of our general partner to ETP, for the 2013 compensation packages to our NEOs, our Compensation Committee considered ETP’s compensation methodology described below as well as our general partner’s pre-Merger compensation methodology in determining the base salaries, bonus targets and long term incentive awards for the NEOs. The pre-Merger compensation methodology took into account the compensation analysis done by Compensation Advisory Partners LLC for the Compensation Committee in 2012, including additional comparative market information provided by Towers Watson. This comparative market information included information regarding compensation practices and programs based on an analysis of other publicly traded master limited partnerships and general industry companies. The master limited partnership group consisted of Boardwalk Pipeline Partners, L.P.; Buckeye Partners LP; Crosstex Energy LP; El Paso Pipeline Partners, L.P.; Enbridge Energy Partners LP; Energy Transfer Partners L.P.; Enterprise Products Partners LP; Holly Energy Partners LP; Kinder Morgan Energy Partners LP; Magellan Midstream Partners LP; NuStar Energy LP; ONEOK Partners LP; Plains All American Pipeline LP; and Spectra Energy Partners LP, as well as a broader group of publicly traded master limited partnerships composed of companies with varying levels of revenue, market capitalization and market maturity, including Markwest Partners L.P., Amerigas Partners LP and Suburban Propane Partners LP, that may compete with our general partner for executive talent.

During 2013, ETP engaged Mercer (US) Inc. (“Mercer”) to conduct a review of the compensation levels of a number of officers across all of its affiliates, including our NEOs, to provide market information with respect to compensation of such officers. In particular, the review by Mercer 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, Mercer benchmarked us against other companies with similar annual revenues and market-capitalization levels. In light of this review, Mercer did not specifically benchmark our NEOs against any particular set of peer companies.

The compensation analysis provided by Mercer 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. The Compensation Committee utilized the information provided by Mercer to ensure that the compensation of our NEOs is competitive with the compensation for executive officers of the companies considered in Mercer’s compensation analysis. Mercer did not provide any non-executive compensation services for ETP or the Partnership during 2013.

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Elements of Compensation

Unless specified to the contrary below, references in this section of the CD&A to “NEOs,” or “executive officers,” does not include Mr. Salinas.

•

Base Salary: Base salary is designed to provide for a competitive fixed level of remuneration 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. For the year ended December 31, 2013, the Compensation Committee utilized ETP’s compensation methodology, as well as the pre-Merger compensation methodology, both as described above. 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 Compensation Committee, with input from the President and Chief Executive Officer (who we sometimes refer to in this CD&A as our Chief Executive Officer), except with respect to the Chief Executive Officer’s own base salary, approves all base salaries for the NEOs. The Summary Compensation Table includes the NEO base salaries that were approved for 2013. Except for the base salary of the Chief Executive Officer, which has been increased for the 2014 calendar year, the base salaries of the other NEOs are expected to remain in effect until July 1, 2014.

•

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. For 2013, annual bonuses were determined under the Sunoco Partners LLC Annual Short-Term Incentive Bonus Plan (the “Bonus Plan”), which replaced the Sunoco Partners LLC Annual Incentive Plan (the “Annual Incentive Plan”) during such 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. In this regard, the Compensation Committee takes into account whether the Partnership achieved or exceeded its earnings before interest, taxes, depreciation, amortization and other non-cash adjustments (“Adjusted EBITDA”) budget for the year (as further described in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Non-GAAP Financial Measures” above), which is approved by the Board of Directors as discussed below. 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.

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 Adjusted EBITDA for a calendar year. In general, the Compensation Committee believes that Partnership performance at or above the Adjusted EBITDA budget would support bonuses to our NEOs ranging up to 120% of their base salaries, with the exception of our Chief Executive Officer, whose short-term annual cash bonus target was set by the Compensation Committee for 2013 at 135% of his 2014 base salary.

In February 2014, the Compensation Committee approved a cash bonus relating to the 2013 calendar year to Mr. Hennigan of $810,000, representing 135% of his 2014 base salary and the bonus target ranges and total bonus pool under which bonuses to NEOs would be awarded for the 2013 calendar year, and the Chief Executive Officer determined the actual cash bonuses for the NEOs, other than his own, within the annual bonus target ranges approved by the Compensation Committee. In approving Mr. Hennigan’s cash bonus for 2013 and the bonus target ranges and pool for the other NEOs, the Compensation Committee took into account the achievement by the Partnership of approximately 102% of its Adjusted EBITDA budget for 2013 as well as the individual performances of these individuals with respect to promoting the Partnership’s financial, strategic and operating objectives for 2013. The individual bonus target ranges for each NEO also reflect the Compensation Committee’s view of the impact of such individual’s efforts and contributions towards (i) achievement of the Partnership’s success in exceeding its internal financial budget, (ii) the development of new projects that are expected to result in increased cash flows from operations in future years, (iii) the completion of mergers, acquisitions or similar transactions that are expected to be accretive to the Partnership and increase distributable cash flow, and (iv) the overall management of the Partnership’s business.


•	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; to provide competitive compensation opportunities that can be realized through attainment of performance

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goals; 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.


•	The elements of compensation under the LTIP. The LTIP provides for two types of awards: restricted units and unit options.

•

Restricted Units. 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 plan. The Compensation Committee will determine the conditions upon which the restricted units granted may become vested or forfeited, and whether or not any such restricted units will have distribution equivalent rights 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.

Prior to the Merger, our equity awards were in the form of restricted unit awards that vested in total on the third anniversary of the grant date and the payout of which was dependent on the Partnership’s achievement of certain performance metrics and the participant’s continued employment (or, as applicable, continued service relationship) with our general partner. After the Merger, all of the restricted units granted have provided for vesting over a specified time period, with vesting based solely on continued employment (or, as applicable, a continued service relationship) as of each applicable vesting date, without regard to the satisfaction of any performance objectives. This change resulted from the Compensation Committee’s determination that vesting based on continued employment (or, as applicable, continued service), rather than the satisfaction of performance objectives, was more generally prevalent with companies in the energy industry.

Also prior to the Merger, the Compensation Committee granted equity awards in January of the following year for performance during the previous year. Under the ETP compensation methodology, equity awards are granted in December of the performance year. Because of the timing of the transition to ETP’s compensation methodology, the Compensation Committee continued the pre-Merger practice for the equity awards for performance during 2012 with such awards being granted in January 2013. Upon transitioning to ETP’s compensation methodology, the equity awards for performance during 2013 were granted in December 2013 rather than January 2014. Thus, the disclosures in this CD&A and accompanying tables regarding equity awards granted in fiscal 2013 include equity awards granted for performance in both the 2012 (the January 2013 grants) and 2013 (the December 2013 grants) fiscal years. Going forward, the Partnership expects to grant one equity award in December of the performance year. In addition, in January 2014, the Compensation Committee approved an additional grant of restricted units to Mr. Hennigan for his performance during 2013.

In January 2013, for their performance relative to the 2012 calendar year, the Compensation Committee approved grants of restricted units to Mr. Hennigan, Ms. Shea-Ballay and Messrs. Lauterbach and Chalson of 40,000 restricted units, 7,000 restricted units, 7,000 restricted units and 7,000 restricted units, respectively. These unit awards provide for vesting at a rate of 20% per year over a five-year period, subject to continued employment through each specified vesting date. In December 2013, as a result of the transition to the ETP compensation methodology, the Compensation Committee approved grants of restricted units to Mr. Hennigan, Ms. Shea-Ballay and Messrs. Lauterbach and Chalson of 43,700 restricted units, 7,000 restricted units, 7,000 restricted units and 7,000 restricted units, respectively. These units vest, based upon continued employment or service, at a rate of 60% after the third year of continuous employment or service and the remaining 40% after the fifth year of continuous employment or service. In addition, in January 2014, the Compensation Committee approved a grant of restricted units to Mr. Hennigan of 5,000 restricted units, which vest, based upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service.

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These restricted units also entitle holders to receive, with respect to each common unit subject to such restricted unit that has not either vested or been forfeited, a distribution equivalent right cash payment promptly following each such distribution by us on our common units to our unitholders. In approving the grant of such restricted units, 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 unit awards subject to vesting.

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 vesting and issuance of the restricted units.

The restricted units under the LTIP generally require the continued employment of the recipient during the vesting period. However, any unvested restricted units granted to a participant who is an employee will become vested and be paid out in the event of the termination of the participant’s employment under circumstances that constitute a “Qualifying Termination” (as defined in the LTIP) within certain periods of time before or after a “Change in Control” (as defined in the LTIP) of the Partnership or permanent disability of the participant prior to the end of the applicable vesting period.

In addition to his role as Chief Financial Officer of our general partner, Mr. Salinas also serves as an employee of ETP’s general partner. Although the compensation committee of ETP’s general partner sets the components of his compensation, including salary and annual bonus, our general partner’s Compensation Committee may make equity awards to Mr. Salinas in recognition of the services provided to us. In January 2013, Mr. Salinas received such equity awards, in the form of 8,333 restricted units granted pursuant to the LTIP, vesting at a rate of 20% per year over a five-year period, subject to continued employment through each specified vesting date. In addition, in December 2013, Mr. Salinas received equity awards, in the form of 6,550 restricted units granted pursuant to the LTIP, vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject to his continued employment through each specified vesting date.

•

Performance-Based Restricted Units. The Company issued performance based restricted units in each of January 2011 and January 2012, with the awards issued in January 2011 vesting as of December 31, 2013, and the awards issued in January 2012 set to vest in December 31, 2014, and the payout of which, in each case, is subject to achievement of certain performance levels. For these performance-based LTIP grants, the Compensation Committee has determined that eventual payout of such LTIP awards will depend upon our achievement of performance levels based on two equally weighted performance measures: total unitholder return (including cash distributions plus appreciation in unit price) relative to peer companies and distributable cash flow, as measured by the distribution coverage ratio (defined as the sum of distributable cash flow divided by the sum of the distributions paid to unitholders) relative to goals defined by the Compensation Committee, both measured over a three-year performance cycle.

Actual payout under these awards may range from zero percent to 200 percent of the units granted to each recipient, based upon our performance with respect to each of these two measures. Payment with respect to earned performance-based restricted units is made in common units no later than March 15 following the end of the performance period.

In selecting total unitholder return and distributable cash flow, as measured by the distribution coverage ratio, as the performance measures applicable to the payout of performance-based restricted units, consideration was given to a balanced incentive approach, utilizing those measures deemed most important to our common unitholders, while recognizing the difficulty of accurately predicting market conditions over time. For these grants, the Compensation Committee believes that performance relative to our peer companies is an important criterion for payout since market conditions are outside the control of management, and management should realize greater than median levels of compensation only when we outperform relative to our peer companies. Conversely, regardless of market conditions, management should realize less than median compensation levels when we underperform as compared to our peer companies. Total unitholder return is a measure of investment performance expressed as total return to unitholders based upon the cumulative return over a three-year period reflecting price appreciation and reinvestment of cash

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distributions during the performance period and is a non-GAAP financial measure. Total unitholder return is measured using a one-month average stock price at the beginning and end of the three-year performance period. Similarly, distribution coverage ratio also is a non-GAAP financial measure that is measured over the same three-year performance period. As an additional incentive to promote the growth of cash distributions to our unitholders during the performance period, distribution equivalent rights were granted in tandem with the performance based restricted unit awards. At the end of the performance period, to the extent that the restricted units are paid out, these distribution equivalent rights entitle the grantee of the restricted units to receive an amount equal to the cumulative cash distributions that otherwise would have been paid over the performance period had the grantee been the holder of record of the number of our common units equal to the number of restricted units paid out. This amount may be taken in the form of cash or additional common units (fractional units are cashed out).


•	Unit Options. The LTIP currently permits the grant of options covering common units. No unit options have been granted since the inception of the LTIP. However, in the future, the Compensation Committee may grant unit options under the LTIP to employees and directors, containing such terms as the Compensation Committee shall determine.

•

Accounting and Tax Considerations. We account for the equity compensation expense of our general partner’s employees, including the NEOs, in accordance with U.S. generally accepted accounting principles (“GAAP”), which requires us to estimate and record an expense for each equity award over the vesting period of the award. For performance-based restricted units that are paid out in the form of common units, the value of our common units on the date of grant is used for determining the expense, with an adjustment for the actual performance factors achieved. Thus, the expense for performance-based restricted units payable in units generally is not adjusted for changes in the trading price of our common units after the date of grant. For market-based awards, the value is determined using a Monte Carlo simulation. 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, our general partner’s Compensation Committee did not consider its impact in determining compensation levels for 2013. In deciding to grant long-term incentive awards of restricted units, rather than unit options, our general partner’s Compensation Committee did consider the tax implications to us.

•

Equity Grant Practices. Equity awards to employees are approved at meetings of our general partner’s Compensation Committee. In exigent circumstances, 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 2013.

•

Unit Ownership Guidelines. Our general partner has established guidelines for the ownership of our common units, applicable to its executives and certain key employees. For executives (including NEOs) and other key employees, 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, while 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. Executive officers who have not yet met their respective 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

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policy, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership guideline.

•

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 incent 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 our general partner’s LTIP.


•	Other Plans: During 2013, employees of our general partner, including the NEOs, participated in the following benefit plans offered by ETP or its affiliates, including certain of Sunoco’s plans, in which our general partner was a participating employer prior to the Merger and continues to participate:

•

The Sunoco, Inc. Retirement Plan (the “SCIRP”) is a qualified defined benefit plan, under which benefits are subject to Code limits for pay and amount. Under the SCIRP, executives hired before January 1, 1987 participate in a “final average pay” formula. Those executives hired on or after January 1, 1987 participate in a “cash balance” formula, which provides a benefit based on career pay rather than final average pay. Effective June 30, 2010, Sunoco froze pension benefits (including accrued and vested benefits) payable under this plan for all salaried employees, including the NEOs of our general partner who participate in this plan.

•

The Sunoco, Inc. Pension Restoration Plan (the “Pension Restoration Plan”) is a non-qualified, unfunded plan that provides retirement benefits that otherwise would be 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, including the NEOs of our general partner who participate in this plan.

•

The Sunoco, Inc. Capital Accumulation Plan (“SunCAP”) 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 100% of their eligible compensation after applicable taxes, as limited under the Code. The general partner makes a matching contribution based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The general partner also makes a discretionary profit sharing contribution of 7% of base pay (Messrs. Hennigan, Lauterbach and Chalson) or 3% of base pay (Ms. Shea-Ballay), subject to IRS contribution limits. The entire amount credited to the participant’s SunCAP account is fully vested and non-forfeitable at all times. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement. Effective January 1, 2014, SunCAP was merged into the ETP 401(k) Plan.

•

The ETP Non-Qualified Deferred Compensation Plan (the “ETP NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary and/or bonus until retirement or termination of employment or other designated distribution event. Under the ETP NQDC Plan, each year eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested unit distribution income, and/or 50% of their discretionary performance bonus compensation to be earned for services performed during the following year. Pursuant to the ETP NQDC Plan, the general partner may make annual discretionary matching contributions to participants’ accounts; however, the general partner 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 NQDC Plan (other than discretionary credits) are immediately 100% 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 accounts 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. 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 change of control (as defined in the ETP NQDC Plan), all ETP NQDC 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 deferred compensation plan established by ETP in connection with the Merger. Pursuant to his Offer Letter (as defined below) agreement with ETP, in connection with the Merger, Mr. Hennigan waived any future rights or benefits to which he

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otherwise would have been entitled under both the Sunoco, Inc. Executive Retirement Plan (“SERP”), a non-qualified, unfunded 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% vested and will be distributed in one lump sum payment upon his retirement or 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 a variety of other benefits arrangements, including medical, dental, vision, life insurance, disability insurance, holidays and vacation. These benefits generally are provided on an enterprise-wide basis to employees of the general partner and its affiliates. Executive officers receive the same benefits and are responsible to pay the same premium as other non-represented employees.


•	Perquisites: In 2013, certain NEOs also received a limited number of personal benefits, or “perquisites.” The dollar amount of the perquisites received by our NEOs is included in the Summary Compensation Table below, under “All Other Compensation.”


•	Severance and Change-in-Control 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. Upon certain terminations of employment and in the event of a change in control, certain benefits may be paid or provided to our NEOs.

•

The Executive Involuntary Severance Plan (the “Involuntary Severance Plan”) provides certain severance benefits to certain of our general partner’s designated executive officers and other designated key management personnel who are involuntarily terminated other than for just cause, death or disability. In recognition of their past service, the plan is intended to alleviate the financial hardship that may be experienced by certain executives whose employment is terminated, due to circumstances beyond their control. The amount or kind of benefit to be provided is based on the executive’s position and compensation at the time of termination. Depending upon salary level, NEOs would receive severance payments ranging from one to one and one-half times base salary plus their annual target bonus in effect on the termination date. Eligible executives under the Involuntary Severance Plan are entitled to medical coverage during the applicable severance period, at the same rate that such benefits are provided to active employees. Following the Merger, the Executive Involuntary Severance Plan was amended to provide that the only eligible participants under the plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger.

•

The Special Executive Severance Plan (the “SESP”) provides severance and enhanced pension benefits in case of termination (whether actual or constructive and other than for just cause, death or disability) occurring within two years after a change of control of the Partnership, as defined in the plan. The plan was adopted to retain key management personnel in the event of a major transaction or change in control, and to eliminate the uncertainty and questions that may arise among management with respect to such transaction, and that may result in the departure or distraction of key management personnel to our detriment and/or to the detriment of our general partner. Under such circumstances, the Board of Directors has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key management personnel to their assigned duties without distraction and, hence, has adopted the plan. The Board of Directors believes that in the context of a change in control, potential acquirers otherwise may have an incentive to constructively terminate an executive’s employment to avoid paying severance, and it is therefore appropriate to provide severance benefits in this circumstance upon a constructive termination. Severance under this plan is payable in a lump sum, equal to three times annual compensation for the Chief Executive Officer, and two times annual compensation for the other NEOs. Following the Merger, the SESP was amended to provide that the only eligible participants under the plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger.

•

The LTIP provides that, in the event of a qualifying termination following a change in control (as such terms are defined in the plan), all awards of restricted units or unit options automatically vest and become payable or exercisable, as the case may be. Performance-based restricted units that have been outstanding for more than one year will be paid out at the greater of the target amount, or an amount in line with our actual

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performance immediately prior to the change in control. Those performance-based restricted units that have been outstanding for one year or less will be paid out at the target amount. Additional information regarding these plans can be found under “Other Potential Post-Employment Payments” below.

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SUMMARY COMPENSATION TABLE

The Summary Compensation Table reflects the total compensation earned by each NEO in each of 2013, 2012 and 2011 (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 ($)	Unit Awards ⁽¹⁾ ($)	Non-Equity Incentive Plan Compensation ⁽²⁾ ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ⁽³⁾ ($)	All Other Compensation ⁽⁴⁾ ($)	Total ($)
M. J. Hennigan	2013	574,750	5,242,400	810,000	—	336,262	6,963,412
President and Chief	2012	539,716	6,533,065	956,174	—	292,351	8,321,306
Executive Officer	2011	488,300	881,954	680,200	589,142	59,536	2,699,132
M. Salinas, Jr. ⁽⁵⁾	2013	n/a	918,464	n/a	n/a	19,562	938,026
Chief Financial Officer	2012	n/a	n/a	n/a	n/a	n/a	n/a
K. Shea-Ballay	2013	310,000	873,390	278,000	—	74,559	1,535,949
Senior Vice President,	2012	290,500	212,582	222,775	19,610	22,606	768,073
General Counsel & Secretary	2011	264,000	117,307	204,900	23,387	21,629	631,223
K. Lauterbach ⁽⁶⁾	2013	313,500	873,390	283,000	489	113,900	1,584,279
Senior Vice President,
Lease Acquisitions
D. Chalson ⁽⁶⁾	2013	266,475	873,390	285,000	15,764	47,033	1,487,662
Senior Vice President,
Operations

NOTES TO TABLE:

⁽¹⁾

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 2013 for additional detail regarding assumptions underlying the value of these equity awards. In addition to the awards approved by the Compensation Committee at its regularly scheduled meetings in January 2013, December 2013, January 2012, February 2012 and January 2011, the amounts shown in this column also reflect the grant of time-based units to Mr. Hennigan, effective December 5, 2012, pursuant to his Offer Letter following the Merger with ETP. Prior to the Merger, the Compensation Committee granted equity awards in January of the following year for performance during the previous year. Under the ETP compensation methodology, equity awards are granted in December of the performance year. Because of the timing of the transition to ETP’s compensation methodology, the Compensation Committee continued the pre-Merger practice for the equity awards for performance during 2012 with such awards being granted in January 2013. Upon transitioning to ETP’s compensation methodology, the equity awards for performance during 2013 were granted in December 2013 rather than January 2014 (which would have been the case under our pre-Merger compensation methodology). Thus, the amounts shown in this column include equity awards granted for performance in both the 2012 (the January 2013 grants) and 2013 (the December 2013 grants) fiscal years. Going forward, it is expected that annual equity awards for performance will be made in December of the performance year.

⁽²⁾

The amounts shown in this column reflect annual bonuses payable under the Bonus Plan for performance during 2013, which are payable on or before March 15, 2014, and annual incentive amounts paid under the Annual Incentive Plan (which was replaced by the Bonus Plan in 2013) for performance during 2012 and 2011, which were paid on or before March 15, 2013 and March 15, 2012, respectively. Under the Annual Incentive Plan, an individual’s annual incentive payout amount was determined by multiplying: (a) the product of his or her base salary and individual incentive guideline by (b) a factor ranging from zero to 200 percent, based upon the level of attainment of specific pre-established goals.

⁽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. Pursuant to Mr. Hennigan’s Offer Letter agreement with ETP, in connection with the Merger, he waived any future rights or benefits to which he otherwise would have been entitled under both the SERP and the Pension Restoration Plan. As a consequence, the year-to-year change in actuarial present value of his pension benefits under the Sunoco plans in 2012 was negative. The year-to-year change in actuarial present value of Mr. Hennigan’s and Ms. Shea-Ballay’s pension benefits under the Sunoco plans for 2013 was negative because the discount rate used in the assumptions to value the lump sum pension benefit was higher in 2013 than it was in 2012. The assumed higher rate results in a lower present value of benefits. The applicable disclosure rules require the change in pension value be shown as “$0” if the actual calculation of the change in pension value is less than zero (i.e., a decrease). The decrease in pension value for Mr. Hennigan was $2,140,896 for 2012. The decrease in pension value for Mr. Hennigan and Ms. Shea-Ballay was $199,350 and $17,954, respectively, for 2013. NEOs did not have any above-market or preferential payments on deferred compensation during 2013, 2012, or 2011. During 2012 and 2011, certain NEOs had deferred amounts under the Sunoco, Inc. Savings Restoration Plan (the “Savings Restoration Plan”), an excess 401

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(k) benefit plan available during 2012 and 2011 to employees of Sunoco and its subsidiaries, including our general partner. The Savings Restoration Plan was a non-qualified deferred compensation plan available to those participants in SunCAP subject to compensation and/or contribution limitations under the Code. Participants were able to contribute amounts in excess of the applicable Code limits, up to five percent of base salary. Effective as of December 31, 2012, the Savings Restoration Plan was terminated, amounts outstanding in participant accounts were liquidated, and the participating employees who were affected by the plan’s termination received the cash value of their outstanding account balances from Sunoco. Mr. Hennigan received payment of his outstanding cash balance at December 31, 2012. Ms. Shea-Ballay received payment of her outstanding cash balance at February 2013.


⁽⁴⁾	The table below shows the components of this column for 2013:



Name	Year	Company Contribution Under Defined Contribution Plan ^(a) ($)	Financial Counseling ^(b) ($)	Perquisites >$10,000 ($)	Distribution Equivalent Rights Payments ^(c) ($)	Total ($)
M. J. Hennigan	2013	28,737	2,350	—	305,175	336,262
M. Salinas, Jr.	2013	n/a	n/a	n/a	19,562	19,562
K. Shea-Ballay	2013	20,400	n/a	—	54,159	74,559
K. Lauterbach	2013	30,600	n/a	—	83,300	113,900
D. Chalson	2013	30,600	n/a	—	16,433	47,033

^(a)

During 2013, our general partner was a participating employer in SunCAP, which makes a matching contribution based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The general partner also makes a discretionary profit sharing contribution of 7% of base pay (Messrs. Hennigan, Lauterbach and Chalson) or 3% of base pay (Ms. Shea-Ballay), subject to IRS contribution limits.

^(b)

In 2006, Mr. Hennigan received perquisites including an allowance for financial counseling up to a maximum of $2,500 per year. This annual financial counseling allowance was discontinued beginning on January 1, 2007, and any unused portion of the 2006 allowance could not be carried forward. However, Mr. Hennigan was permitted to continue to use amounts accrued prior to 2005, until such balance was depleted. In April 2013, Mr. Hennigan’s financial counseling account was closed, and the remaining balance of $2,350 was paid to him.


^(c)	The amounts shown in this column reflect the cash payments made to each NEO during 2013, which were equal to each cash distribution per common unit made by us on our common units during 2013 with respect to each common unit subject to a restricted unit held by such NEO that has not either vested or been forfeited.

⁽⁵⁾

Mr. Salinas is employed by the general partner of ETP, which determines the components of his compensation, including salary and annual bonus. We have no control over this compensation determination process. However, our general partner’s Compensation Committee granted equity awards to Mr. Salinas in January and December 2013 in recognition of his services to us. Mr. Salinas did not receive separate compensation for his services to us as Chief Financial Officer of our general partner during 2012.


⁽⁶⁾	Compensation information only for fiscal year 2013 is provided for the employees of our general partner who were not NEOs in fiscal years 2011 and 2012.

118

GRANTS OF PLAN-BASED AWARDS

The following table sets forth the grants of plan-based awards to NEOs in 2013:



Name	Grant Date	All Other Unit Awards: Number of Units (#)	Grant Date Fair Value of Unit Awards ⁽¹⁾ ($)
M. J. Hennigan	12/5/2013 ⁽²⁾	43,700	2,971,600
President and Chief Executive Officer	1/24/2013	40,000	2,270,800
M. Salinas, Jr.	12/5/2013 ⁽²⁾	6,550	445,400
Chief Financial Officer	1/24/2013	8,333	473,064
K. Shea-Ballay	12/5/2013 ⁽²⁾	7,000	476,000
Senior Vice President, General Counsel & Secretary	1/24/2013	7,000	397,390
K. Lauterbach	12/5/2013 ⁽²⁾	7,000	476,000
Senior Vice President, Lease Acquisitions	1/24/2013	7,000	397,390
D. Chalson	12/5/2013 ⁽²⁾	7,000	476,000
Senior Vice President, Operations	1/24/2013	7,000	397,390

NOTES TO TABLE:


⁽¹⁾	Reflects the grant date fair value of restricted unit awards granted under the LTIP during fiscal 2013, computed in accordance with FASB ASC Topic 718. See Note 14 to our consolidated financial statements for fiscal 2013 for additional detail regarding assumptions underlying the value of these equity awards.

⁽²⁾

Prior to the Merger, the Compensation Committee granted equity awards in January of the following year for performance during the previous year. Under the ETP compensation methodology, equity awards are granted in December of the performance year. Because of the timing of the transition to ETP’s compensation methodology, the Compensation Committee continued the pre-Merger practice for the equity awards for performance during 2012 with such awards being granted in January 2013. Upon transitioning to ETP’s compensation methodology, the equity awards for performance during 2013 were granted in December 2013 rather than January 2014.

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, along with the information provided in this section.

In connection with the consummation of the Merger, Mr. Hennigan accepted an offer letter from ETP, effective as of October 5, 2012, to continue in his current positions as the President and Chief Executive Officer, and a director of our general partner (the “Offer Letter”). The terms of the Offer Letter include the following:


•	Base salary of $550,000, on an annualized basis;


•	2012 target bonus opportunity at 100% of base salary;


•	Retention of Mr. Hennigan’s right to certain benefits in the event of termination of employment or a change in control of our general partner under the SESP for a period of two years from the effective time of the Merger. The Offer Letter amended and limited the events giving rise to a “Qualifying Termination” under the SESP;

•

One-time award, granted as of December 5, 2012, under the LTIP, consisting of 90,000 restricted units and cash distribution rights, vesting incrementally over a five-year period. The first percentage vesting will occur on October 6, 2014 (the “Initial Vesting Date”), and all distributions associated with the award prior to the Initial Vesting Date will be accrued, but not paid, until the Initial Vesting Date;


•	Eligibility, on a discretionary basis, for annual long-term equity incentive awards, consisting of our restricted units having a grant date fair value equal to 200 percent to 300 percent of annual base salary (subject to a five-year graded vesting period);


•	Conversion of the present value ($2,789,413) of certain Sunoco deferred compensation benefits to the ETP Deferred Compensation Plan for Former Sunoco Executives; and


•	Eligibility to participate in the employee benefit plans, including non-qualified deferred compensation, retirement, health and other welfare benefit plans, offered to similarly situated executives of ETP.

119

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, 2013:



Name		Unit Awards
		Time-based Awards		Performance-based Awards
	Grant Date ⁽¹⁾	Number Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ⁽²⁾ ($)	Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested ⁽³⁾ (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ⁽²⁾ ($)
M. J. Hennigan	12/5/2013	43,700	3,298,476
President and Chief Executive Officer	1/24/2013	32,000	2,415,360
	12/5/2012	90,000	6,793,200
	3/1/2012	19,535	1,474,502
	3/1/2012			35,033	2,644,291
M. Salinas, Jr.	12/5/2013	6,550	494,394
Chief Financial Officer	1/24/2013	6,666	503,150
K. Shea-Ballay	12/5/2013	7,000	528,360
Senior Vice President,	1/24/2013	5,600	422,688
General Counsel & Secretary	1/26/2012			6,152	464,353
K. Lauterbach	12/5/2013	7,000	528,360
Senior Vice President,	1/24/2013	5,600	422,688
Lease Acquisitions	7/24/2012	29,260	2,208,545
	1/26/2012			5,381	406,158
D. Chalson	12/5/2013	7,000	528,360
Senior Vice President, Operations	1/24/2013	5,600	422,688
	1/26/2012			2,071	156,319

NOTES TO TABLE:


⁽¹⁾	Time-based restricted unit awards vest as follows:


•	100% in December 2014 for Mr. Hennigan’s award granted in March 2012;


•	100% in December 2014 for M. Lauterbach’s award granted in July 2012;


•	ratably in December of each year through 2017 for awards granted in December 2012;


•	ratably in December of each year through 2017 for awards granted in January 2013; and


•	60% in December 2016 and the remaining 40% in December 2018 for awards granted in December 2013.

The performance-based restricted unit awards vest in December 2014.

⁽²⁾

The market value or payout value of the unearned restricted units assumes a payout at the target of 100 percent, and is equal to the closing price of our common units on December 31, 2013 of $75.48, multiplied by the number of restricted units outstanding. The amounts shown in this column do not include amounts for related distribution equivalents that could be included in the payout. See “Other Potential Post-Employment Payments” for a discussion of the treatment of these awards under certain termination events, or in the event of a change in control.

⁽³⁾

Actual payout of performance-based awards will depend upon our achievement of certain specified performance levels based on defined goals. The portion of each award that may be earned during the performance period ranges from zero to 200 percent of the award. Payment of any amounts earned will occur following the vesting period, assuming continued employment with the general partner at such time. See “Other Potential Post-Employment Payments” for a discussion of the treatment of these awards under certain termination events, or in the event of a change in control.

120

OPTION EXERCISES AND UNITS VESTED

The following table provides information concerning the vesting in 2013 of certain restricted units, previously awarded under the LTIP to the NEOs:



Name	Unit Awards
Name	Number of Units Acquired on Vesting ⁽¹⁾ (#)	Value Realized on Vesting ⁽²⁾ ($)
M. J. Hennigan	61,934	4,600,802
President and Chief Executive Officer
M. Salinas, Jr.	1,667	114,456
Chief Financial Officer
K. Shea-Ballay	15,980	1,191,374
Senior Vice President, General Counsel & Secretary
K. Lauterbach	31,201	2,082,761
Senior Vice President, Lease Acquisitions
D. Chalson	6,716	495,462
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 2013. For the performance-based restricted units, the number of common units to be paid out was determined by multiplying the target number of such restricted units by the applicable performance factor (200%).


⁽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 vesting date. These amounts do not reflect the value of units withheld by our general partner to satisfy tax withholding obligations.

121

PENSION BENEFITS

Prior to the Merger, our general partner was a participating employer in certain Sunoco pension and retirement plans, and our general partner continues to participate in such plans following the Merger. Our NEOs are eligible to participate in such plans. The table below shows the estimated annual retirement benefits payable to a covered executive based upon the final average pay formula or the cash balance formula, as applicable, of the SCIRP and the Pension Restoration Plan. Executives who participate in these plans may elect to receive their accrued benefits in the form of either a lump sum or an annuity. The estimates shown in the table below assume that benefits are received in the form of a single lump sum at retirement. Effective June 30, 2010, Sunoco froze pension benefits for all salaried and many non-union employees. This freeze also applies to the NEOs.



Name	Plan	Number of Years Credited Service ⁽¹⁾ (#)	Present Value of Accumulated Benefit Year-end 2012 ⁽²⁾ ($)	Payments During Last Fiscal Year ($)
M. J. Hennigan ⁽³⁾	SCIRP (Qualified)	27.93	1,199,976	—
President and Chief Executive Officer	Pension Restoration	27.93	—	—
M. Salinas, Jr. ⁽⁴⁾	SCIRP (Qualified)	n/a	n/a	n/a
Chief Financial Officer	Pension Restoration	n/a	n/a	n/a
K. Shea-Ballay	SCIRP (Qualified)	5.19	144,459	—
Senior Vice President, General Counsel & Secretary	Pension Restoration	5.19	11,904	—
K. Lauterbach	SCIRP (Qualified)	12.73	227,563	—
Senior Vice President, Lease Acquisitions	Pension Restoration	12.73	—	—
D. Chalson	SCIRP (Qualified)	24.18	464,783	—
Senior Vice President, Operations	Pension Restoration	24.18	10,812	—

NOTES TO TABLE:


⁽¹⁾	Credited years of service reflect actual service with the general partner, including years of service credited with Sunoco prior to employment with our general partner.

⁽²⁾

An actuarial present value of the benefits is calculated by estimating expected future payments starting at an assumed retirement age, weighting the estimated payments by the estimated probability of surviving to each post-retirement age, and discounting weighted payments at an assumed discount rate to reflect the time value of money. The actuarial present value represents an estimate of the amount which, if invested as of December 31, 2013 at a discount rate of 4.65%, would be sufficient on an average basis to provide estimated future payments based on the current accumulated benefit. Estimated future payments are assumed to be in the form of a single lump sum payment at retirement determined using interest rate and mortality table assumptions applicable under current IRS regulations for qualified pension plans. All pre-retirement decrements such as pre-retirement mortality and terminations of employment have been ignored for purposes of these calculations. The lump sum conversion uses the lump sum mortality table derived from IRS regulations. In addition, the value of the lump sum payment includes the estimated value of the 50% postretirement death benefit payable, if married, to the spouse of a retired participant under the Final Average Pay formula benefits described below. It is assumed that 80% of all male members are married and 50% of females are married, with wives assumed to be 3 years younger than husbands. The assumed retirement age for each executive is the earliest age at which the executive could retire without any benefit reduction due to age. For NEOs, the assumed retirement age is 60 (i.e., the earliest age at which the executive could retire without any benefit reduction due to age), or actual age, if older than 60. 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.

⁽³⁾

Pursuant to his Offer Letter agreement with ETP, in connection with the Merger, 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 the ETP Deferred Compensation Plan for Former Sunoco Executives.


⁽⁴⁾	Mr. Salinas is employed by ETP’s general partner and does not participate in any of the Sunoco pension benefit plans.

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The Sunoco, Inc. Retirement Plan

The SCIRP is a qualified defined benefit retirement plan that covers most salaried and many hourly employees, including the NEOs. The SCIRP provides for normal retirement at age 65. The plan includes two benefit formulas:


(1)	Final Average Pay formula


•	The benefit equals (A) 1-²/₃ percent of Final Average Pay (the average earnings during the 36 consecutive months of highest earnings in the last ten years prior to retirement, or until June 30, 2010, whichever is sooner) multiplied by the credited service up to 30 years, plus³/₄ percent of Final Average Pay multiplied by the credited service over 30 years.


•	The benefit is then reduced by (B) an amount equal to 1-²/₃ percent of the estimated Social Security Primary Insurance amount multiplied by the credited years of service up to a maximum of 30 years.

•

The (A) portion of the benefit is reduced by ⁵/₁₂ percent for each month that retirement precedes age 60 (down to age 55), with the early retirement benefit at age 55 being 75 percent of the unreduced benefit. The (B) portion of the benefit is reduced by ⁷/₁₂ percent for each month that retirement precedes age 65 and an additional ⁷/₂₄ percent for each month that retirement precedes age 60, with the reduction at age 55 being 47.5% of the unreduced benefit.


(2)	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 ($110,100 in 2012 and $113,700 in 2013) plus 12 percent of pay that exceeds the Wage Base for the year.


•	The indexing adjustment equals the account balance at the end of each month multiplied by the monthly change in the All-Urban Consumer Price Index, plus 0.17 percent. However, if in any month the adjustment would be negative, the adjustment would be zero for such month.

For employees, including NEOs, hired before January 1, 1987 (Mr. Hennigan), the benefits under the SCIRP are the greater of the Final Average Pay or Career Pay formula benefits. An employee may retire at the Normal Retirement Age of 65 regardless of years of service, or may retire as early as age 55 with 10 years of service. All employees hired before January 1, 1987 are 100 percent vested in their benefits. For employees, including NEOs, hired on or after January 1, 1987 (Ms. Shea-Ballay and Messrs. Lauterbach and Chalson), retirement benefits are calculated under the Career Pay formula only. An employee may retire at the Normal Retirement Age of 65, or may retire as early as age 55 with 10 years of service. An employee hired before January 1, 2008 is 40 percent vested in his or her benefit after completing two years of eligible service, and 100 percent vested after completing three years of eligible service. Employees hired on or after January 1, 2008 are 100 percent vested after three years of eligible service.

The normal form of benefit under the SCIRP is 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 is free for participants who benefit under the Final Average Pay formula, but the participant’s monthly annuity is reduced actuarially for those who benefit under the Career Pay formula. Other forms of payment are also offered such as a lump sum and other annuity options. Under the Career Pay formula, the lump sum is equal to the value of the employee’s account, and under the Final Average Pay formula, the lump sum is the actuarial equivalent of the annuity benefit, based on Internal Revenue Service prescribed interest rates and mortality tables.

The SCIRP is subject to qualified plan Code limits on the amount of annual benefit that may be paid, and on the amount of compensation that may be taken into account in calculating retirement benefits, under the plan. For 2011, the limit on the compensation that may be used was $245,000. The limit on annual compensation that could be considered in calculating benefits in 2012 and 2013 was $250,000 and $255,000, respectively. Benefits in excess of those permitted under the statutory limits are paid from the Pension Restoration Plan, as described below.

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.

If the benefit is paid in a lump sum, the actual amount distributed would vary from the amount provided in the table depending on the actual interest rate and the mortality assumptions used to calculate the distribution at the time of retirement. The mortality table and interest rates to be used in determining a lump sum are set in accordance with the Pension Protection Act of 2006 (“PPA”). Under the PPA, the method for computing the lump sum interest rate was completely phased-in for 2013.

123

Sunoco, Inc. Pension Restoration Plan

The Pension Restoration Plan is a non-qualified plan that provides retirement benefits that would be provided under the SCIRP, but are prohibited from being paid from the SCIRP by the Code limits. See the discussion regarding the SCIRP, above, for the limits. Participants in the SCIRP whose annual compensation exceeds the applicable Code limits are eligible to participate in the Pension Restoration Plan. The benefit paid by the Pension Restoration Plan is the excess of the total benefit accrued under the SCIRP over the amount of benefit that the SCIRP is permitted to provide under the Code. All benefits under the Pension Restoration Plan that are paid in a lump sum are calculated using the same actuarial factors applicable under the SCIRP. 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.

Pursuant to his Offer Letter agreement with ETP, in connection with the Merger, Mr. Hennigan waived any future rights or benefits to which he otherwise would have been entitled under 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 the ETP Deferred Compensation Plan for Former Sunoco Executives.

124

NONQUALIFIED DEFERRED COMPENSATION

Savings Restoration Plan

The following table includes deferred compensation provided to the NEOs in 2013 under the Savings Restoration Plan, a nonqualified plan made available to employees who participated in SunCAP (Sunoco’s 401(k) plan) and who may be subject to Code limits on compensation and/or contributions. Under the Savings Restoration Plan, the participants were able to contribute to an account in excess of the applicable limits. Because the Savings Restoration Plan was nonqualified, the executive’s contributions and our general partner’s matching contributions were credited, and cash distributions are made upon payout. The investment funds available under the Savings Restoration Plan were the same as those available to all employees participating in the SunCAP, and the executive received earnings on those investments, depending on the fund’s performance, calculated in the same manner and at the same rate as for all other employees invested in those funds in the SunCAP. Effective as of December 31, 2012, the Savings Restoration Plan was terminated, amounts outstanding in participant accounts were liquidated, and the affected participating employees received the cash value of their outstanding account balances from Sunoco.



Name	Executive Contributions in 2013 ($)	Registrant Contributions in 2013 ($)	Aggregate Earnings in 2013 ⁽¹⁾ ($)	Aggregate Withdrawals/ Distributions ⁽²⁾ ($)	Aggregate Balance at December 31, 2013 ($)
M. J. Hennigan	—	—	—	—	—
President and Chief Executive Officer
M. Salinas, Jr.	n/a	n/a	n/a	n/a	n/a
Chief Financial Officer
K. Shea-Ballay	—	—	134	6,125	—
Senior Vice President, General
Counsel & Secretary
K. Lauterbach	—	—	—	—	—
Senior Vice President, Lease Acquisitions
D. Chalson	—	—	—	—	—
Senior Vice President, Operations

NOTES TO TABLE:


⁽¹⁾	These amounts reflect the net gains (losses) attributable to the investment funds in which the NEOs are deemed to have chosen to invest their contributions and our general partner’s matching contributions under the Savings Restoration Plan, which are based on how their contributions under SunCAP are invested.


⁽²⁾	Ms. Shea-Ballay received payment of her outstanding cash balance at February 2013.

ETP Non-Qualified Deferred Compensation Plan

The following table provides the voluntary salary deferrals made by the NEOs in 2013 under the ETP NQDC Plan, a deferred compensation plan that permits eligible highly compensated employees to defer a portion of their salary and/or bonus until retirement or termination of employment or other designated distribution event. Under the ETP NQDC Plan, each year eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested unit distribution income, and/or 50% of their discretionary performance bonus compensation to be earned for services performed during the following year. Pursuant to the ETP NQDC Plan, the general partner may make annual discretionary matching contributions to participants’ accounts; however, the general partner 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 NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings (or losses) based on hypothetical investment fund choices made by the participants among available funds.

125



Name	Executive Contributions in 2013 ($)	Registrant Contributions in 2013 ($)	Aggregate Earnings in 2013 ⁽¹⁾ ($)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at December 31, 2013 ($)
M. J. Hennigan	—	—	—	—	—
President and Chief Executive Officer
M. Salinas, Jr.	n/a	n/a	n/a	n/a	n/a
Chief Financial Officer
K. Shea-Ballay	—	—	—	—	—
Senior Vice President, General
Counsel & Secretary
K. Lauterbach	—	—	—	—	—
Senior Vice President, Lease Acquisitions
D. Chalson	50,000	—	3,951	—	53,951
Senior Vice President, Operations

NOTES TO TABLE:


⁽¹⁾	These amounts reflect the net gains (losses) attributable to the investment funds in which the NEOs are deemed to have chosen to invest their contributions under the ETP NQDC Plan.

ETP Deferred Compensation Plan for Former Sunoco Executives

The following table includes deferred compensation provided to the NEOs in 2013 under the ETP Deferred Compensation Plan for Former Sunoco Executives, a deferred compensation plan established by ETP in connection with the Merger. Pursuant to his Offer Letter agreement with ETP, in connection with the Merger, 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 2013 ($)	Registrant Contributions in 2013 ($)	Aggregate Earnings in 2013 ⁽¹⁾ ($)	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at December 31, 2013 ($)
M. J. Hennigan	—	—	486,775	—	3,276,188
President and Chief Executive Officer
M. Salinas, Jr.	n/a	n/a	n/a	n/a	n/a
Chief Financial Officer
K. Shea-Ballay	—	—	—	—	—
Senior Vice President, General
Counsel & Secretary
K. Lauterbach	—	—	—	—	—
Senior Vice President, Lease Acquisitions
D. Chalson	—	—	—	—	—
Senior Vice President, Operations

NOTES TO TABLE:


⁽¹⁾	These amounts reflect the net gains (losses) attributable to the investment funds in which the NEOs are deemed to have chosen to invest their contributions under the ETP Deferred Compensation Plan for Former Sunoco Executives.

126

OTHER POTENTIAL POST-EMPLOYMENT PAYMENTS

Certain plans, described below, provide for payments of benefits to the NEOs in connection with termination, or separation from employment, retirement, or a change in control of our general partner, or in some cases, Sunoco. The actual amounts paid can be determined only at the time of such NEO’s separation from employment with our general partner. The following describes the benefits that the NEOs would receive if such an event occurred. Mr. Salinas is employed by the general partner of ETP, and he does not participate in participate in the retirement, severance, or termination plans either of Sunoco or of our general partner.


•	Retirement: The benefits paid to the NEOs upon retirement are described above in the section entitled “Pension Benefits.”


•	LTIP: Under the LTIP, if an NEO is eligible for retirement, outstanding performance-based restricted units would continue to vest, and would pay out, along with the accompanying distribution equivalent rights, if the performance measures are met. Outstanding time-based restricted units would be forfeited.


•	Voluntary Termination: An NEO who resigns and leaves voluntarily, would receive the following benefits:

•

SCIRP/Pension Restoration Plan: Retirement eligible NEOs hired prior to January 1, 1987 (Mr. Hennigan) would receive benefits based upon the Final Average Pay formula of the SCIRP, which is a qualified defined benefit retirement plan. Effective January 1, 1987, for employees hired subsequent to that date, the SCIRP was converted from a final average pay plan to a cash balance pension plan. SCIRP benefits for NEOs hired after this conversion (Ms. Shea-Ballay and Messrs. Lauterbach and Chalson) are calculated using the Career Pay formula, based on a percentage of pay each year and an indexing adjustment. Normal retirement age under the SCIRP is 65 years. To the extent that the amount payable exceeds the maximum amount that may be paid under the SCIRP, the remaining amount would be paid under the Pension Restoration Plan. Effective June 30, 2010, Sunoco froze pension benefits for all salaried and many non-union employees. This freeze also applies to the NEOs.


•	LTIP: Under the LTIP, outstanding performance-based restricted units would be cancelled as of the termination date. Outstanding time-based restricted units would be forfeited.


•	Bonus Plan: If an NEO voluntarily terminates employment prior to the payment date under the Bonus Plan, he or she would not receive any bonus for that year.


•	Vacation Benefits: Each NEO would be entitled to receive payment for his or her accrued vacation, which benefit is generally provided to active employees of the Partnership’s general partner.


•	Involuntary Termination-For Cause: An NEO who is terminated for cause would receive the following:


•	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 LTIP, outstanding performance-based restricted units would be cancelled as of the termination date. Outstanding time-based restricted units would be forfeited.


•	Bonus Plan: If an NEO is terminated prior to the payment date under the Bonus Plan, he or she would not receive any bonus for that year.


•	Vacation Benefits: Each NEO would receive payment for his or her accrued vacation, which benefit is generally provided to active employees of the Partnership’s general partner.


•	Involuntary Termination-Not for Cause: An NEO who is terminated not for cause would receive the following:

•

Involuntary Severance Plan: Executives whose employment is terminated by the Partnership’s general partner, other than for just cause, receive a severance allowance under the Involuntary Severance Plan in consideration of signing a release of liability in favor of the general partner and its affiliates. The plan is available to the general partner’s NEOs and certain other executive level employees. Following the Merger, the Involuntary Severance Plan was amended to provide that the only eligible participants under the plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger. The following is a summary of the benefits available under this plan:


•	In the case of the Chief Executive Officer, severance payments would be for a period of and equal to 78 weeks of base salary plus the target bonus amount, in effect on the termination date, as defined in the plan.


•	Other NEOs would receive severance payments for a period of and equal to 52 weeks of base salary plus target bonus amount, in effect on the termination date, as defined in the plan.

127


•	Each NEO would be entitled to medical coverage for up to the period of severance received, at the same rate that such benefits are generally provided to active employees.


•	NEOs would receive a cash amount in lump sum equal to the NEO’s accrued but unused vacation through the end of his or her employment termination date as defined in the plan.


•	Each NEO would be entitled to outplacement benefits for up to the period of severance received.

•

SCIRP/Pension Restoration Plan: NEOs hired prior to January 1, 1987 (Mr. Hennigan) would receive benefits based upon the Final Average Pay formula of the SCIRP. SCIRP benefits for NEOs hired after the January 1, 1987 conversion of SCIRP from a final average pay plan to a cash balance pension plan (Ms. Shea-Ballay and Messrs. Lauterbach and Chalson) are calculated using the Career Pay formula. To the extent that the amount payable exceeds the amount available under the SCIRP, the remaining amount would be paid under the Pension Restoration Plan.


•	LTIP: Under the LTIP, outstanding performance-based restricted units would be cancelled as of the termination date. Outstanding time-based restricted units would be forfeited.


•	Involuntary Termination-Change of Control

•

SESP: This plan was adopted to retain executives in the event of a change of control, and to eliminate the distraction and uncertainty such a transaction may create among management personnel, to the detriment of the organization. Following the Merger, the SESP was amended to provide that the only eligible participants under the plan are those employees who were eligible to participate on October 5, 2012, the date of the Merger. Payment of severance benefits under this plan provides severance allowances to executives whose employment is terminated in connection with, or following, a change of control. A “change of control” is defined as any one or more of the following events:


•	a transaction pursuant to which more than 50 percent of the combined voting power of the outstanding equity interests in the general partner cease to be owned by Sunoco and its affiliates;


•	a “Change in Control” of Sunoco, as defined from time to time in the Sunoco stock plans; or


•	the general partner of the Partnership ceases to be an affiliate of Sunoco.

There is a “double trigger” mechanism for the payment of severance benefits under this plan, requiring both a change of control and a qualifying termination of employment (as defined in the plan) following such change of control to trigger payment. Severance benefits under this plan are paid in a lump sum equal to three times annual compensation for the CEO, and two times annual compensation for the other NEOs. For these purposes, annual compensation consists of:


•	the executive’s annual base salary in effect immediately prior to a change of control or immediately prior to the employment termination date, whichever is greater, plus


•	the greater of 100 percent of the executive’s annual bonus target in effect immediately before the change of control or employment termination date.

Although the SESP contains a formula for severance benefits, Mr. Hennigan’s severance upon a change of control was set at $3,026,793 pursuant to his October 5, 2012 Offer Letter agreement with ETP.

Each eligible NEO would be entitled to medical, dental, vision and life insurance coverage for the period of severance received, at the same rate that such benefits are generally provided to active employees of the general partner. Each eligible NEO would also be entitled to outplacement benefits for the period of severance received. In the case of a change of control, the plan also provides for the enhancement of certain pension benefits.


•	SCIRP: In the event of a change of control, the benefits of a participant whose employment began before September 5, 2001, and who is terminated (as defined in the plan) following a change in control, become 100 percent vested and are increased as follows:

•

Final Average Pay formula. A participant’s service is increased by three years, subject to reduction for service for each completed month after the change in control. Final Average Pay will be the greater of: (A) the regularly determined Final Average Pay, (B) Final Average Pay based on earnings of the full month preceding the change in control, or (C) Final Average Pay based on earnings for the month preceding the termination of employment. For purposes of (B) and (C) monthly earnings will include base pay and¹/₁₂ of the annual bonus target under the Bonus Plan.


•	Career Pay (cash balance) formula. A participant’s service is increased by three years, subject to reduction for service after the change in control. In the month of termination, a participant’s Career

128

Pay Earnings are increased by an amount equal to 36 months less the number of months worked after the Change in Control, times the greater of Career Pay Earnings for: (A) the month preceding termination or (B) the month preceding the change in control. For purposes of (A) and (B) monthly earnings will include base pay and¹/₁₂ of the annual bonus target under the Bonus Plan.

•

LTIP: 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 performance-based restricted units and accompanying distribution equivalent rights. Performance-based restricted units that have been outstanding for more than one year will be paid out at the greater of target or in amount in line with actual performance results. Performance-based restricted units that have been outstanding for less than one year will be paid out at target. Upon the same “double trigger” mechanism, time-based units will be paid out as awarded. Restricted units may be paid out in cash, or in common units, as determined by our general partner’s Compensation Committee.


•	Death: In the case of death, an NEO’s beneficiary(ies) or estate would receive the following benefits:


•	Insurance:


•	Life insurance benefits equal to one times base compensation up to a maximum of $1 million plus any supplemental life insurance elected and paid for by the NEO.


•	Travel accident insurance in the amount of three times base compensation (up to a maximum of $3 million) would be payable in the event of accidental death while traveling on company business.


•	An occupational death benefit in the amount of $250,000 would be payable in the event of accidental death on the company’s premises in the course of his job; however, the Occupational Death Plan does not pay benefits if there is a Travel Accident benefit of three times base compensation.


•	If the NEO is married and retirement-eligible at the time of death, medical coverage would be available to his or her spouse on the same basis as other surviving spouses of retirement-eligible employees. If not retirement-eligible at death, coverage for the spouse would be available for a period that is consistent with the requirements of COBRA continuation coverage.


•	SCIRP/Pension Restoration Plan:

•

With respect to an NEO who is eligible for Final Average Pay formula benefits under SCIRP (Mr. Hennigan), his or her spouse would receive the greater of: (A) 50 percent of the benefit under the Final Average Pay formula, or (B) 100 percent of the benefit accrued under the Career Earnings Formula. A non-married NEO’s beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.


•	With respect to an NEO that is eligible for Career Pay Formula benefits only under SCIRP (Ms. Shea-Ballay and Messrs. Lauterbach and Chalson), a married or non-married NEO’s spouse, beneficiary(ies) or estate would receive 100 percent of the benefit accrued under the Career Earnings Formula. This benefit is the same for all similarly situated employees.


•	For all NEOs, to the extent that the amount payable under SCIRP exceeds the amount available due to Code limits, the remaining amount would be paid under the Pension Restoration Plan at the employee’s death.

•

LTIP: Under the LTIP, all unvested performance-based restricted units would continue to vest, and, along with the accompanying distribution equivalent rights, would pay out at the end of the respective performance periods to the NEO’s beneficiary(ies) or estate if the applicable performance measures are met. Outstanding time-based restricted units would be forfeited unless specified in the applicable award agreement.


•	Disability: In the case of a termination of employment due to disability, an NEO would be eligible for the following benefits:


•	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.


•	Long Term Disability: An NEO would receive benefits, including Social Security, up to 60 percent of total annual compensation or $25,000 per month, whichever is less, under Sunoco’s long-term disability plan.


•	LTIP: Under the LTIP all unvested performance-based restricted units would continue to vest, and along with

129

the accompanying distribution equivalent rights, will pay out at the end of the respective performance periods if the applicable performance measures are met. All unvested time-based restricted units will be paid out as awarded in the event of permanent disability.

Except for Mr. Salinas (as explained above), the tables on the following pages 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 an NEO’s termination of employment. These estimates are based on the following assumptions:


•	the applicable provisions in the agreements and arrangements governing the NEOs’ benefits and payment which are summarized in the section entitled “Other Potential Post-Employment Payments”;


•	the triggering event occurred on December 31, 2013;


•	the transaction price per Partnership unit is $75.48, which was the price at the close on December 31, 2013;


•	pension lump-sum values are based on applicable segment interest rates under the Pension Protection Act of 2006;


•	health and welfare benefits are included, where applicable, at the estimated value of the continuation of these benefits; and


•	each NEO has exhausted all available vacation benefits as of December 31, 2013.

130

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2013

Michael J. Hennigan

President and Chief Executive Officer



Type of Benefit	Voluntary Termination ($)	Death ($)	Disability ($)	Termination for Cause ($)	Involuntary Termination Not for Cause ($)	Change in Control ($)
Cash Severance ⁽¹⁾
Base Salary	—	—	—	—	862,125	—
Bonus	—	—	—	—	1,163,869	—
Total Cash Severance	—	—	—	—	2,025,994	3,026,793
Additional Pension Benefits ⁽²⁾	—	—	—	—	113,204	113,204
Unit Ownership ^{(3) (4)}
Performance-Based Restricted Units (2012-2014) ⁽⁵⁾	—	2,776,079	2,776,079	—	2,776,079	2,776,079
Time-Vested Restricted Units ⁽⁵⁾	—	8,552,477	14,341,433	—	14,341,433	14,341,433
Total Unit Ownership	—	11,328,556	17,117,512	—	17,117,512	17,117,512
Other Benefits
Outplacement ⁽⁶⁾	—	—	—	—	19,125	19,125
Health & Welfare ⁽⁷⁾	—	—	—	—	150,000	150,000
Total Other Benefits	—	—	—	—	169,125	169,125
TOTAL	—	11,328,556	17,117,512	—	19,425,835	20,426,634

NOTES TO TABLE:


⁽¹⁾	Pursuant to Mr. Hennigan’s October 5, 2012 Offer Letter agreement with ETP, his severance upon a Change in Control is $3,026,793. Upon involuntary termination not for cause, consists of 78 weeks of the sum of base salary and target bonus in effect on the termination date.


⁽²⁾	Pursuant to his October 5, 2012 Offer Letter agreement with ETP, in connection with the Merger, 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 (both non-qualified plans). Value shown in the table reflects additional qualified pension benefits.


⁽³⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $75.48 (closing price of the Partnership on December 31, 2013). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.


⁽⁴⁾	Pursuant to the terms of a letter agreement with Mr. Hennigan, dated November 2, 2011, in the event of his involuntary termination not for cause, Mr. Hennigan’s time-based restricted units will continue to vest and pay out, and his performance-based restricted units will be treated as described below for a Change in Control event.

⁽⁵⁾

Upon a Change in Control, performance-based restricted units outstanding more than twelve months from the grant date are paid out at the greater of target or actual performance immediately prior to the Change in Control. The estimated payout for the 2012 performance cycle would have been 100% of target based on Total Return and Distribution Coverage Ratio. Performance-based restricted units outstanding less than twelve months from the grant date prior to a Change in Control are not adjusted for any performance factors. Under death, disability and retirement, outstanding performance-based restricted units would continue to the end of the performance period, and payment, if any, would be based as though the participant had continued to be employed through the end of the performance period. Assumed to be paid at target under these scenarios. Upon a Change in Control, time-based restricted units would be paid out as awarded. Under permanent disability, time-based restricted units would be paid at the end of the retention period as though the participant had continued to be employed through the end of the retention period. Mr. Hennigan’s October 5, 2012 Offer Letter agreement with ETP provides for vesting of the restricted units granted in December 2012 immediately upon death, disability and involuntary not-for-cause termination. Mr. Hennigan’s award agreement for restricted units granted in March 2012 provides for vesting immediately upon death and disability.


⁽⁶⁾	Reimbursement for outplacement services ($12,750 per annum) as provided by our general partner during the severance period (78 weeks).


⁽⁷⁾	Pursuant to the terms of a November 2, 2011 letter agreement, Mr. Hennigan will receive a lump sum payment of $150,000 in lieu of our general partner’s regular subsidy for post-employment benefits.

131

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2013

Martin Salinas, Jr. ⁽¹⁾

Chief Financial Officer



Type of Benefit	Voluntary Termination ($)	Death ($)	Disability ($)	Termination for Cause ($)	Involuntary Termination Not for Cause ($)	Change in Control ($)
Cash Severance
Base Salary	—	—	—	—	—	—
Bonus	—	—	—	—	—	—
Total Cash Severance	—	—	—	—	—	—
Additional Pension Benefits	—	—	—	—	—	—
Unit Ownership ⁽²⁾
Performance-Based Restricted Units (2012-2014)	—	—	—	—	—	—
Time-Vested Restricted Units	—	—	1,013,192	—	—	1,013,192
Total Unit Ownership	—	—	1,013,192	—	—	1,013,192
Other Benefits
Outplacement	—	—	—	—	—	—
Health & Welfare	—	—	—	—	—	—
Total Other Benefits	—	—	—	—	—	—
TOTAL	—	—	1,013,192	—	—	1,013,192

NOTES TO TABLE:


⁽¹⁾	Mr. Salinas does not participate in the retirement, termination, or severance plans of Sunoco Partners LLC.


⁽²⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $75.48 (closing price of the Partnership on December 31, 2013). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

132

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2013

Kathleen Shea-Ballay

Senior Vice President, General Counsel and Secretary



Type of Benefit	Voluntary Termination ($)	Death ($)	Disability ($)	Termination for Cause ($)	Involuntary Termination Not for Cause ($)	Change in Control ($)
Cash Severance
Base Salary ⁽¹⁾	—	—	—	—	310,000	620,000
Bonus ⁽²⁾	—	—	—	—	232,500	465,000
Total Cash Severance	—	—	—	—	542,500	1,085,000
Additional Pension Benefits	—	—	—	—	124,515	124,515
Unit Ownership ⁽³⁾
Performance-Based Restricted Units (2012-2014) ⁽⁴⁾	—	490,092	490,092	—	—	490,092
Time-Vested Restricted Units ⁽⁴⁾	—	—	980,627	—	—	980,627
Total Unit Ownership	—	490,092	1,470,719	—	—	1,470,719
Other Benefits
Outplacement ⁽⁵⁾	—	—	—	—	12,750	12,750
Health & Welfare ⁽⁶⁾	—	—	—	—	14,270	14,270
Total Other Benefits	—	—	—	—	27,020	27,020
TOTAL	—	490,092	1,470,719	—	694,035	2,707,254

NOTES TO TABLE:


⁽¹⁾	Consists of 2.0 x multiple of the base salary prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of base salary in effect on the termination date.


⁽²⁾	Consists of 2.0 x multiple of the target bonus prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of target bonus in effect on the termination date.


⁽³⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $75.48 (closing price of the Partnership on December 31, 2013). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

⁽⁴⁾


⁽⁵⁾	Reimbursement for outplacement services ($12,750 per annum) as provided by our general partner during the severance period (52 weeks).


⁽⁶⁾	Health & Welfare and life insurance coverage during the severance period (52 weeks). Annual medical costs provided by our general partner. Dental coverage is not provided upon involuntary termination not for cause.

133

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2013

Kurt Lauterbach ⁽¹⁾

Senior Vice President, Lease Acquisitions



Type of Benefit	Voluntary Termination ($)	Death ($)	Disability ($)	Termination for Cause ($)	Involuntary Termination Not for Cause ($)	Change in Control ($)
Cash Severance
Base Salary	—	—	—	—	—	—
Bonus	—	—	—	—	—	—
Total Cash Severance	—	—	—	—	—	—
Additional Pension Benefits	—	—	—	—	128,807	214,392
Unit Ownership ⁽²⁾
Performance-Based Restricted Units (2012-2014) ⁽³⁾	428,651	428,651	428,651	—	—	428,651
Time-Vested Restricted Units ⁽³⁾	—	2,306,127	3,270,321	—	—	3,270,321
Total Unit Ownership	428,651	2,734,778	3,698,972	—	—	3,698,972
Other Benefits
Outplacement	—	—	—	—	—	—
Health & Welfare	—	—	—	—	—	—
Total Other Benefits	—	—	—	—	—	—
TOTAL	428,651	2,734,778	3,698,972	—	128,807	3,913,364

NOTES TO TABLE:


⁽¹⁾	Mr. Lauterbach is not eligible for severance benefits, as the SESP and Involuntary Severance Plan were amended following the Merger to provide that the only eligible participants under those plans were employees who were eligible to participate on October 5, 2012, the date of the Merger.


⁽²⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $75.48 (closing price of the Partnership on December 31, 2013). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

⁽³⁾

Upon a Change in Control, performance-based restricted units outstanding more than twelve months from the grant date are paid out at the greater of target or actual performance immediately prior to the Change in Control. The estimated payout for the 2012 performance cycle would have been 100% of target based on Total Return and Distribution Coverage Ratio. Performance-based restricted units outstanding less than twelve months from the grant date prior to a Change in Control are not adjusted for any performance factors. Under death, disability and retirement, outstanding performance-based restricted units would continue to the end of the performance period, and payment, if any, would be based as though the participant had continued to be employed through the end of the performance period. Assumed to be paid at target under these scenarios. Upon a Change in Control, time-based restricted units would be paid out as awarded. Under permanent disability, time-based restricted units would be paid at the end of the retention period as though the participant had continued to be employed through the end of the retention period. Mr. Lauterbach’s award agreement for restricted units granted in July 2012 provides for vesting immediately upon death and disability.

134

Sunoco Logistics Partners L.P.

Other Potential Post-Employment Payments as of December 31, 2013

David R. Chalson

Senior Vice President, Operations



Type of Benefit	Voluntary Termination ($)	Death ($)	Disability ($)	Termination for Cause ($)	Involuntary Termination Not for Cause ($)	Change in Control ($)
Cash Severance
Base Salary ⁽¹⁾	—	—	—	—	266,475	532,950
Bonus ⁽²⁾	—	—	—	—	253,151	506,303
Total Cash Severance	—	—	—	—	519,626	1,039,253
Additional Pension Benefits	—	—	—	—	119,025	181,380
Unit Ownership ⁽³⁾
Performance-Based Restricted Units (2012-2014) ⁽⁴⁾	164,999	164,999	164,999	—	—	164,999
Time-Vested Restricted Units ⁽⁴⁾	—	—	980,627	—	—	980,627
Total Unit Ownership	164,999	164,999	1,145,626	—	—	1,145,626
Other Benefits
Outplacement ⁽⁵⁾	—	—	—	—	12,750	12,750
Health & Welfare ⁽⁶⁾	—	—	—	—	14,270	14,270
Total Other Benefits	—	—	—	—	27,020	27,020
TOTAL	164,999	164,999	1,145,626	—	665,671	2,393,279

NOTES TO TABLE:


⁽¹⁾	Consists of 2.0 x multiple of the base salary prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of base salary in effect on the termination date.


⁽²⁾	Consists of 2.0 x multiple of the target bonus prior to the Change in Control. Upon involuntary termination not for cause, consists of 52 weeks of target bonus in effect on the termination date.


⁽³⁾	Reflects intrinsic values of accelerated vesting of equity awards at an assumed closing price of $75.48 (closing price of the Partnership on December 31, 2013). Values include unvested/unearned distribution equivalent rights of accelerated vesting of unit ownership.

⁽⁴⁾


⁽⁵⁾	Reimbursement for outplacement services ($12,750 per annum) as provided by our general partner during the severance period (52 weeks).


⁽⁶⁾	Health & Welfare and life insurance coverage during the severance period (52 weeks). Annual medical costs provided by our general partner. Dental coverage is not provided upon involuntary termination not for cause.

135

DIRECTOR COMPENSATION

Compensation Philosophy: The Board of Directors 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 of Directors 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 Welch, directors who are also employees of our general partner, or its affiliates, receive no additional compensation for service on the general partner’s Board of Directors or any committees of the Board of Directors. As such, those officers, except for Messrs. McCrea and Welch 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 of Directors 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. At times, a director may travel to and from Board of Directors and/or committee meetings on corporate aircraft. 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 of Directors, to the extent permitted under applicable state law.

Our program of compensation for non-employee directors was approved by our general partner following the consummation of the Merger and became effective during the 2013 calendar year. This director compensation program consists of an annual cash retainer and equity award for all directors, which were $50,000 in cash (paid quarterly) and 1,649 restricted units under the LTIP, having a fair market value equal to $100,000 on the date of grant, respectively, for each director in 2013. 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 2013;


•	annual retainers for the members of the Audit and Compensation Committees, which were $10,000 and $5,000, respectively, in cash (paid quarterly) for 2013; and


•	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 2013.

The members of the Conflicts Committee also each received $15,000 in cash for their service on the Conflicts Committee during 2013, which payment was determined by the Board of Directors as compensation for evaluation of transactions by the Conflicts Committee. In addition, each non-employee director who is elected or appointed to the Board of Directors for the first time is entitled to receive an award of 2,500 restricted units under the LTIP.

Since the current slate of directors was appointed in connection with the Merger, each non-employee director listed in the table below was entitled to an award of 2,500 restricted units under the LTIP. These awards, as well as the annual equity awards of 1,649 restricted units under the LTIP, were granted to each non-employee director in March 2013. In addition, in January 2014, each non-employee director received 1,334 restricted units under the LTIP, having a fair market value equal to $100,000 on the date of grant, representing such directors’ annual equity award for 2014. These restricted units vest over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject to each director’s continued service through each specified vesting date.

Mr. McCrea, the Chairman of the Board of Directors and the President, Chief Operating Officer and Director of ETP’s general partner, and Mr. Welch, our director and the Group Chief Financial Officer and Head of Business Developments for the Energy Transfer family, are entitled to receive grants of restricted units pursuant to the LTIP in recognition of their commitment and contributions to us and our unitholders. In January 2013, Mr. McCrea received 16,667 restricted units granted pursuant to the LTIP, vesting at a rate of 20% per year over a five-year period, subject to his continued employment through each specified vesting date. In addition, in December 2013, Mr. McCrea received 27,300 restricted units granted pursuant to the LTIP, vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject to his continued service as a director through each specified vesting date. In January 2014, Mr. Welch received 5,450 restricted units granted pursuant to the LTIP, vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject to his continued service as a director through each specified vesting date.

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.

136

The following table reflects the compensation paid to each of the non-employee directors of our general partner (and to Mr. McCrea, as described above) in 2013:



Name	Fees Earned or Paid in Cash ⁽¹⁾ ($)	Unit Awards ⁽²⁾ ($)	All Other Compensation ⁽³⁾ ($)	Total ($)
Steven R. Anderson	100,028	271,345	7,479	378,852
Independent Director, Chair of Conflicts Committee and Member of Audit and Compensation Committee
Scott A. Angelle	101,881	271,345	7,479	380,705
Independent Director, Chair of Compensation Committee and Member of Audit and Conflicts Committees
Basil Leon Bray	103,778	271,345	7,479	382,602
Independent Director, Chair of Audit Committee and Member of Compensation and Conflicts Committees
Marshall S. ("Mackie") McCrea, III	—	2,802,586	39,126	2,841,712
Chairman of the Board of Directors

NOTES TO TABLE:


⁽¹⁾	The amounts shown in this column reflect the cash fees received by directors during 2013


⁽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 2013 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 2013, which were equal to each cash distribution per common unit made by us on our common units during 2013 with respect to each common unit subject to a restricted unit held by such director that has not either vested or been forfeited.

137

COMPENSATION PRACTICES AS THEY RELATE TO RISK MANAGEMENT

The Compensation Committee has oversight responsibility to ensure that our incentive compensation programs do not incentivize or encourage excessive or unnecessary risk-taking/wrong behavior. The following is a description of the compensation risk assessment process, as well as a description of our compensation risk mitigation techniques.

An executive’s compensation package includes a mix of base salary, cash-based short-term incentives, and equity-based long-term incentives. The mix is designed to balance the emphasis on short-term and long-term performance. Performance metrics applicable to short-term and long-term incentives have included a mix of financial and non-financial goals, some of which have been relative to our performance peers. The long-term metrics for the 2013 performance-based restricted units were total unitholder return and growth in cash distributions to unitholders relative to our peers. This approach creates a balance of absolute and relative performance to ensure that executives are rewarded when sustained results exceed our peer group.

The Compensation Committee reviews and approves the annual and long-term plan performance metrics and goals annually. As a part of this process, the Compensation Committee focuses on what executive behavior it is attempting to incent and the potential associated risks. The Compensation Committee periodically receives financial information from the CFO, and information on accounting matters that may have an impact on the performance goals, including any material changes in accounting methodology and information about extraordinary/special items excluded by us and from our peer companies’ results, so that the Compensation Committee members may understand how the exercise of management judgment in accounting and financial decisions affects plan payouts.

We maintain unit ownership guidelines for our top executives. The amount of our common units required to be owned increases with the level of responsibility. Requiring an executive to hold a substantial portion of accumulated wealth in our common units, which must be held until the executive retires or otherwise leaves the employ of our general partner or its affiliates, aligns his or her behavior towards long-term unitholder value creation. See “Compensation Discussion & Analysis-Elements of Compensation-Long-Term Incentive Awards (Equity Awards)-Unit Ownership Guidelines” for additional information.

Employees of our general partner and its affiliates are subject to our Insider Trading Policy, which, among other things, prohibits an employee from entering into short sales, or purchasing, selling, or exercising any puts, calls or similar instruments pertaining to our securities, all of which could incent an employee towards engaging in overly risky behavior for short-term gains.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

Messrs. Angelle, Anderson, Bray, Hennigan and McCrea served on the Compensation Committee during 2013. Mr. Hennigan is an officer of our general partner, and Mr. McCrea is an officer of the general partner of ETP. During 2013, 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 board of directors.

138

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 Chief Executive Officer (“CEO”) and the other executive officers (collectively, the “Named Executive Officers” or “NEOs”) 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 of Directors, 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, 2013, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 24, 2014 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

139

AUDIT COMMITTEE REPORT

The Audit Committee (the “Committee”) of the Board of Directors of Sunoco Partners LLC (the “Company”) reviews the Partnership’s financial reporting process on behalf of the Board of Directors of the Company. The Company is the general partner of the Partnership. Our 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 our internal control over financial reporting. The Committee monitors and oversees these processes.

The Committee discussed with our 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 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 2013 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 of Directors, 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, 2013, for filing with the Securities and Exchange Commission.

Respectfully submitted on February 24, 2014 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

140



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, 2013, regarding our common units that may be issued upon conversion (assuming a one-for-one conversion) of outstanding restricted units granted under the general partner’s LTIP to executive officers, directors, and other key employees. For more information about this plan (which did not require approval by our limited partners at the time of its adoption in 2002), refer to “Item 11-Executive Compensation.”

EQUITY COMPENSATION PLAN INFORMATION ⁽¹⁾



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	—	—	—
Equity compensation plans not approved by security holders ⁽²⁾	770,579	—	611,906
Total	770,579	—	611,906

NOTES TO TABLE:

⁽¹⁾

The amounts in column (a) of this table reflect only restricted units that have been granted under the LTIP since the inception of the plan. No unit options have been granted. 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 may be conditioned upon achievement of pre-determined financial or other performance objectives for, or attainment 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 maximum payment (i.e., a 200% ratio) has been assumed for vesting and payout of performance-related grants, and a target payout (i.e., a 100% ratio) has been assumed for vesting and payout of grants conditioned only upon service.


⁽²⁾	The LTIP was not approved by our unitholders because the Board of Directors adopted the LTIP prior to our initial public offering.

141

Beneficial Ownership Table

The following table sets forth the beneficial ownership of our common units by directors of Sunoco Partners LLC (our general partner), by each NEO and by directors and NEOs of Sunoco Partners LLC as a group, as of February 17, 2014. Unless otherwise noted, each individual exercises sole voting or investment power over the Partnership common units shown in the table. ETP owns a 99.9% equity interest in our general partner, and the remaining 0.10% equity interest is owned by ETE Holdings.



Name of Beneficial Owner ⁽¹⁾	Number of Common Units Beneficially Owned ⁽²⁾	Percentage of Common Units Beneficially Owned
Energy Transfer Partners, L.P. ⁽³⁾	33,530,637	32.2	%
Steven R. Anderson	5,000	*
Scott A. Angelle	—	*
Basil Leon Bray	—	*
Michael J. Hennigan ⁽⁴⁾	101,861	*
Thomas P. Mason	—	*
Marshall S. ("Mackie") McCrea, III	13,935	*
Martin Salinas, Jr.	6,117	*
Jamie Welch	—	*
Kathleen Shea-Ballay	15,869	*
Kurt A. Lauterbach	40,352	*
David R. Chalson	36,908	*
All directors and executive officers as a group (11 persons)	220,042	*



*	Less than 0.5 percent.

NOTES TO TABLE:


⁽¹⁾	The address of each beneficial owner named above, other than ETP, is: 1818 Market Street, Suite 1500, Philadelphia, PA 19103.


⁽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⁾	ETP’s address is 3738 Oak Lawn Avenue, Dallas, TX 75219.


⁽⁴⁾	Mr. Hennigan’s spouse has voting and investment power with respect to 7,200 of these units.

In addition to the foregoing, Tortoise Capital Advisors, L.L.C., a Delaware limited liability company, filed a Schedule 13G on February 11, 2014 to report that, as of December 31, 2013, it had shared voting power over 8,928,197 common units of the Partnership, and beneficial ownership of, and shared dispositive power over 9,810,169 common units of the Partnership, representing 9.4 percent of the total outstanding common units of the Partnership, as of February 17, 2014.

142

The following table sets forth certain information regarding beneficial ownership of the common units representing limited partnership interests of ETP as of February 18, 2014 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	2,890	*
Michael J. Hennigan ⁽²⁾	7,333	*
Thomas P. Mason ⁽³⁾	92,692	*
Marshall S. ("Mackie") McCrea, III ⁽³⁾	206,574	*
Martin Salinas, Jr. ⁽³⁾	45,326	*
Jamie Welch ⁽³⁾	20,000	*
Kathleen Shea-Ballay	947	*
Kurt A. Lauterbach	—	*
David R. Chalson	—	*
All directors and executive officers as a group (11 persons)	385,787	*



*	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⁾	Mr. Hennigan’s spouse has voting and investment power with respect to 3,205 of these ETP common units.


⁽³⁾	Due to their positions as 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.

143



ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

On February 5, 2010, our general partner, Sunoco Partners LLC, completed the sale of 6.6 million common units of the Partnership in a registered public secondary offering.

On October 5, 2012, Sunoco, Inc. (“Sunoco”) was acquired by Energy Transfer Partners, L.P. (“ETP”). Prior to this transaction, Sunoco (through its wholly-owned subsidiary Sunoco Partners LLC) served as the Partnership’s general partner and owned a two percent general partner interest, all of the Partnership’s incentive distribution rights and a 32.4 percent limited partner interest in the Partnership. In connection with the acquisition, Sunoco’s interests in the general partner and limited partnership were contributed to ETP, resulting in a change of control of the Partnership’s general partner. As a result, the Partnership became a consolidated subsidiary of ETP on the acquisition date.

In July 2013, the limited liability company agreement of Sunoco Partners LLC was amended to reflect the addition of ETE Common Holdings, LLC ("ETE Holdings") as an owner of a 0.1 percent membership interest in our general partner. ETE Holdings is a wholly-owned subsidiary of Energy Transfer Equity, L.P. and an affiliate of ETP. In addition, the 33.5 million common units in us owned by Sunoco Partners LLC were assigned to ETP.

As of February 17, 2014, ETP, the controlling owner of our general partner, owns a 33.6 percent partnership interest in us, which includes a two percent general partner interest (through its controlled subsidiary Sunoco Partners LLC) and 33.5 million common units, representing a 32.2 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.

Distribution and Payments to the General Partner and Its Affiliates

The following table summarizes the distribution and payments made and to be made us to the general partner and its affiliates in connection with the ongoing operation 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, $15 million for the year ended December 31, 2013, 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.

Concurrently with and subsequent to the closing of the 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, been assigned and been extended or replaced. These agreements include the Omnibus Agreement, the Pipelines and Terminals Storage and Throughput Agreement, the Interrefinery Lease Agreement, an intellectual property license agreement, certain crude oil purchase and sale agreements, a treasury services agreement, 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.”

144

Approval and Review of Related Party Transactions

Our Partnership Agreement and the Omnibus Agreement each contain provisions for our Conflicts Committee, comprised 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 Partnership and its subsidiaries and affiliates, a Code of Ethics for Senior Officers of the Partnership and its subsidiaries and affiliates, and a Conflict of Interest Policy applicable to all directors, officers and employees of the Partnership and its subsidiaries and affiliates. Each of these policies requires the approval by a supervisor, officer, or the Board of Directors, 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.

145



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 year ended December 31, 2013. Ernst & Young LLP served as our independent registered public accountant for the year ended December 31, 2012.

The following table presents the aggregate fees billed by Grant Thornton LLP and Ernst & Young LLP for audit and other professional services for the years ended December 31, 2013 and 2012:



	Grant Thornton LLP		Ernst & Young LLP
	For the Year Ended December 31,		For the Year Ended December 31,
Type of Fee	2013		2012
	(in millions)
Audit Fees⁽¹⁾	$	1.0	$	1.8
Audit Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—
	$	1.0	$	1.8

⁽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 and review of registration statements and issuance of comfort letters, 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 of directors prior to their performance. All services rendered by Grant Thornton LLP and Ernst & Young 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.

146

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 Distribution L.P. and Butane Acquisition I LLC, dated as of June 25, 2010 (incorporated by reference to Exhibit 2.1 of Form 8-K, 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(2) to furnish any such schedules and exhibits to the SEC supplementally, upon request (incorporated by reference to Exhibit 2.1.1 of Form 8-K, file No. 1-31219, filed August 4, 2010)

3.1*		Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 to Form S-1 Registration Statement, file No. 333-71968, filed October 22, 2001)

3.2*		Certificate of Limited Partnership of Sunoco Logistics Operations L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 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 3.5 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)

3.4.1*		Amendment No. 1 to Third Amended and Restated Partnership Agreement 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)

3.5*		Third Amended and Restated Limited Liability Company Agreement of Sunoco Partners LLC dated as of July 1, 2011 (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-31219, filed July 5, 2011)

3.5.1*		Amendment No. 2 to Third Amended and Restated Partnership Agreement 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)

3.6*		Fourth Amended and Restated Limited Liability Company Agreement of Sunoco Partners LLC, dated July 11, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-31219, filed July 17, 2013)

3.7*		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 (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*		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)

147




Exhibit No.		Description

4.1.2*		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)

10.1		$1,500,000,000 Credit Agreement dated as of November 19, 2013, 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 L/C Issuer; and the other Lenders Party thereto

10.2*		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)

10.3*		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)

10.3.1*		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)

10.4*		Amended and Restated Treasury Services Agreement, dated as of November 26, 2003, by and among Sunoco, Inc., Sunoco Logistics Partners L.P., and Sunoco Logistics Partners Operations L.P. (incorporated by reference to Exhibit 10.7.1 of Form 10-K, file No. 1-31219, filed March 4, 2004)

10.5*		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)

10.6*		Inter-refinery 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)

10.7*		Sunoco Partners LLC Executive Involuntary Severance Plan, as amended and restated as of July 27, 2010 (incorporated by reference to Exhibit 10.1 of Form 10-Q, file No. 1-31219, filed August 4, 2010)

10.7.1*		Amendment No. 2012-2 to the Sunoco Partners LLC Executive Involuntary Severance Plan (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-31219, filed January 7, 2013)

10.8*		Sunoco Partners LLC Long-Term Incentive Plan, as amended and restated as of October 24, 2012 (incorporated by reference to Exhibit 10.3 of Form 10-Q, file No. 1-31219, filed November 8, 2012)

10.8.1*		Form of Performance-Based Restricted Unit Agreement under the Sunoco Partners LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.11.1 of Form 10-K, file No. 1-31219, filed February 23, 2011)

148




Exhibit No.		Description

10.8.2*		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)

10.9		Sunoco Partners LLC Annual Short-Term Incentive Bonus Plan, dated as of January 1, 2013

10.10*		Sunoco Partners LLC Special Executive Severance Plan, as amended and restated as of July 27, 2010 (incorporated by reference to Exhibit 10.5 of Form 10-Q, file No. 1-31219, filed August 4, 2010)

10.10.1*		Amendment No. 2012-2 to the Sunoco Partners LLC Special Executive Severance Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-31219, filed January 7, 2013)

10.11**		Crude Oil Pipeline Throughput and Deficiency Agreement between Motiva Enterprises LLC and Sunoco Pipeline L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.19 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.12**		Marine Dock and Terminalling Agreement between Motiva Enterprises LLC and Sunoco Partners Marketing & Terminals L.P., dated as of December 19, 2006 (incorporated by reference to Exhibit 10.20 of Form 10-K, file no. 1-31219, filed February 23, 2007)

10.13*		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)

10.14*		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)

10.14.1*		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)

10.15*		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)

10.16*		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)

10.17*		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)

10.18*		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)

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 10.14.1 to Form 10-K, file No. 1-31219, filed March 4, 2004)

16.1*		Letter from Ernst & Young LLP to the Securities and Exchange Commission, dated April 4, 2013, regarding the change in certifying accountant (incorporated by reference to Exhibit 16.1 of Form 8-K, file No. 1-31219, filed April 4, 2013)

21.1		Subsidiaries of Sunoco Logistics Partners L.P.

23.1		Consent of Grant Thornton LLP

23.2		Consent of Ernst & Young LLP

149



Exhibit No.		Description

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

99.1*		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)

99.2*		Termination Agreement by and between Sunoco, Inc., and Lynn L. Elsenhans, dated April 29, 2012 (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-31219, filed May 2012)

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, 2013 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.

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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/ MARTIN SALINAS, JR.

		Martin Salinas, Jr.
		Chief Financial Officer

February 27, 2014

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 27, 2014.





STEVEN R. ANDERSON*		MICHAEL J. HENNIGAN*

Steven R. Anderson Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.		Michael J. Hennigan Director, President and Chief Executive Officer of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Executive Officer)

SCOTT A. ANGELLE*		THOMAS P. MASON*

Scott A. Angelle 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.

BASIL LEON BRAY*		MARSHALL S. MCCREA III*

Basil Leon Bray 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.

MICHAEL D. GALTMAN*		JAMIE WELCH*

Michael D. Galtman Controller and Chief Accounting Officer of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P. (Principal Accounting Officer)		Jamie Welch Director of Sunoco Partners LLC, General Partner of Sunoco Logistics Partners L.P.

151