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2014 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, 2014



¨	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 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 4.25%, due April 1, 2024		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
Senior Notes 5.30%, due April 1, 2044		New York Stock Exchange
Senior Notes 5.35%, due May 15, 2045		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 $6.7 billion as of June 30, 2014, based on $47.11 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on that date. At February 25, 2015, the number of the registrant’s Common Units outstanding were 229,588,587.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS




PART I		2
ITEM 1.	BUSINESS	2
ITEM 1A.	RISK FACTORS	17
ITEM 1B.	UNRESOLVED STAFF COMMENTS	32
ITEM 2.	PROPERTIES	32
ITEM 3.	LEGAL PROCEEDINGS	33
ITEM 4.	MINE SAFETY DISCLOSURES	33

PART II		34
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITYHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES	34
ITEM 6.	SELECTED FINANCIAL DATA	35
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	60
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	104
ITEM 9A.	CONTROLS AND PROCEDURES	104
ITEM 9B.	OTHER INFORMATION	104

PART III		105
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	105
ITEM 11.	EXECUTIVE COMPENSATION	111
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITYHOLDER MATTERS	142
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	145
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	147

PART IV		148
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	148

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, refined products and NGLs 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 effect of changes in accounting principles and tax laws and interpretations of both;


•	Global and domestic economic repercussions, including disruptions in the crude oil, refined petroleum products and NGLs 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 35 states, located throughout the United States. Our reporting segments are as follows:

•

The Crude Oil Pipelines transport crude oil in the southwest and midwest United States, principally in Oklahoma and Texas. The segment contains approximately 5,300 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 the West Texas Gulf Pipe Line Company ("West Texas Gulf"), a wholly-owned subsidiary, a controlling financial interest in Mid-Valley Pipeline Company ("Mid-Valley"), and an equity interest in SunVit Pipeline LLC ("SunVit").


•	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 335 crude oil transport trucks and approximately 135 crude oil truck unloading facilities, as well as third-party assets.

•

The Terminal Facilities consist of crude oil, refined products and NGL terminals, as well as a refined products and NGL acquisition and marketing business. The segment operates with an aggregate storage capacity of approximately 48 million barrels, including the 25 million barrel Nederland, Texas crude oil and NGL terminal; the 6 million barrel Eagle Point, New Jersey refined products and crude oil terminal; the 3 million barrel Marcus Hook, Pennsylvania refined products and NGL facility (the "Marcus Hook Industrial Complex"); 39 active refined products marketing terminals located in the northeast, midwest and southwest United States; and refinery terminals located in the northeast United States.

•

The Products Pipelines consist of approximately 2,400 miles of refined products and NGL pipelines, and joint venture interests in four products pipelines in several regions of the United States. The pipelines primarily transport refined products and NGLs in the northeast, midwest and southwest United States to markets in these areas, as well as Ontario, Canada. These operations include our controlling financial interest in Inland, which owns approximately 350 miles of products pipeline.

In 2014, we continued to expand our crude oil pipeline capacity with the commencement of operations on several projects in Texas, as well as the addition of incremental throughput on projects that began operations in prior years. We also increased activity in the pipeline transportation, storage, and acquisition and marketing of NGLs in the northeastern United States with

additional pipeline throughput on the delivery of ethane from the Marcellus Shale Basin to Ontario and activities at our Marcus Hook Industrial Complex. Operational results from these activities have been included in our Products Pipelines and Terminal Facilities segments. We will continue to expand our NGL platform through previously announced growth projects that are expected to commence operations throughout 2015 and 2016.

Our primary business strategies focus on generating stable cash flows, increasing pipeline and terminal throughput, utilizing our acquisition and marketing assets to maximize value, pursuing economically accretive organic growth opportunities and improving 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, refined products and NGL pipelines, terminalling, and acquisition and marketing assets. While this integration creates opportunities and synergies within our operations, assets are sometimes repurposed among our business lines to maximize their utility and profitability. We will continue to utilize our assets in a manner that favors our consolidated results.

Crude Oil Pipelines

The crude oil pipelines consist of approximately 5,800 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States. These pipelines include ownership of the West Texas Gulf pipelines, a controlling financial interest in the Mid-Valley pipeline, as well as a 50 percent ownership interest in a joint venture to construct the SunVit pipeline. Our pipelines access several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, 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,
	2014	2013	2012
Pipeline throughput (thousands of barrels per day ("bpd"))	2,125	1,866	1,556

Southwest United States

Our pipelines in the southwest United States include approximately 3,150 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 1,050 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 December 2014, we acquired an additional 28.3 percent ownership interest in the West Texas Gulf Pipe Line Company ("West Texas Gulf") from Chevron Pipe Line Company, increasing our controlling financial interest in this consolidated subsidiary to 88.6 percent. The remaining 11.4 percent ownership interest was acquired from Southwest Pipeline Holding Company, LLC ("Citgo") in January 2015. These transactions resulted in a wholly-owned interest in a strategic crude pipeline running from Colorado City to Goodrich and Longview, Texas.

In the third quarter 2013, we entered into an agreement to form 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 Mainline Pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon's Samaria, Michigan tank farm, which supplies its refinery in Detroit, Michigan.

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 335 crude oil transport trucks and approximately 135 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 acquisitions in the Crude Oil Acquisition and Marketing business since December 31, 2010:


•	EDF Trading North America - In May 2014, we acquired a crude oil purchasing and marketing business from EDF Trading North America, LLC ("EDF") which consisted of a crude oil acquisition and marketing business and related assets which handle 20 thousand barrels per day. The acquisition also included conversion of a promissory note convertible to equity in a rail facility (see below).


•	Price River Terminal - In May 2014, we acquired a 55 percent economic and voting interest in Price River Terminal, LLC ("PRT"), a rail facility in Wellington, Utah. The terms of the acquisition provide the facility's noncontrolling interest holders the option to sell their interests to us at a defined price. The entity is reflected as a consolidated subsidiary from the date of acquisition.


•	Texon Acquisition and Marketing - 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.

In May 2014, we entered into a joint agreement to form Bayview Refining Company, LLC ("Bayview") which provisioned Bayview to construct and operate a facility that will process crude oil into intermediate petroleum products. The facility is expected to commence operations in the second half of 2015.

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 pipeline. The trucking services are performed either by our truck fleet or a third-party trucking operation.

Crude oil purchasers who buy from producers compete on the basis of price and the ability to provide highly responsive services. Our management believes that our ability to offer competitive pricing and high-quality field and administrative services to producers is a key factor in our ability to maintain our volume of lease purchased crude oil and to obtain new volume.

We also enter into exchange agreements to enhance margins throughout the acquisition and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more nearly matches our delivery requirements or the preferences of our refinery customers, we exchange our physical crude oil with third parties. Generally, we enter into exchanges to acquire crude oil of a desired quality in exchange for a common grade crude oil or to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs.

Generally, we enter into contracts with producers at market prices for a term of one year or less, with a majority of the transactions on a 30-day renewable basis. For the year ended December 31, 2014, we purchased 402 thousand bpd from approximately 3 thousand producers who operate approximately 64 thousand active leases. We also undertook 471 thousand barrels per day 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,
	2014	2013	2012
	(in thousands of bpd)
Lease purchases:
Available for sale	378	332	283
Exchanged	14	7	6
Other exchanges and bulk purchases	481	410	384
Total Purchases	873	749	673

Bulk Sales	483	419	342
Exchanges:
Purchased at the lease	14	7	6
Other	372	321	321
Total Sales	869	747	669

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 without pronounced backwardation or contango), represents the most difficult environment for our marketing activities.

Crude Oil Trucking

We own approximately 135 crude oil truck unloading facilities in the mid-continent United States with the majority located on our pipeline systems. Approximately 500 crude oil truck drivers are employed by an affiliate of our general partner and we own and operate a proprietary fleet of approximately 335 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 48 million barrels. Since December 31, 2010, we completed the following acquisitions in the terminalling business:


•	Marcus Hook Industrial Complex - In April 2013, we acquired Sunoco's Marcus Hook Industrial Complex and related assets. The acquisition included terminalling and storage assets with a capacity of approximately 3 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 6 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 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,
	2014	2013	2012
Refined products throughput (thousands of bpd)	414	431	487

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 and NGLs Acquisition and Marketing

Our refined products and NGLs acquisition and marketing activities include the acquisition, blending, marketing and selling of these products at our various terminals and third-party facilities. Since the acquisition of our butane blending business in 2010, we have continued to expand our butane blending service platform by installing our blending technology at certain of our refined product terminals, as well as at third-party facilities. We also expanded our operations in the NGL market with the acquisition of the Marcus Hook Industrial Complex in 2013. The operating results of our refined products and NGLs acquisition and marketing activities are dependent on our ability to execute sales in excess of the aggregate cost, and therefore we structure our acquisition and marketing operations to optimize the sources and timing of purchases and minimize the transportation and storage costs. In order to manage exposure to volatility in products prices, our policy is to (i) only purchase products for which sales contracts have been executed or for which ready markets exist, (ii) structure sales contracts so that price fluctuations do not materially impact the margins earned, and (iii) not acquire and hold physical inventory, futures contracts or other derivative instruments for the purpose of speculating on commodity price changes. However, we do utilize a 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, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, 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 25 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 third-party pipelines, including the Department of Energy (“DOE”). The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve's West Hackberry caverns at Hackberry, Louisiana and Big Hill near Winnie, Texas, which have an aggregate storage capacity of approximately 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 DOE.

The Nederland Terminal can also receive NGLs in connection with the Mariner South pipeline project, which commenced initial operations in December 2014. The project provides transportation of propane and butane products from the Mont Belvieu region to the Nederland Terminal, where such products can be delivered via ship. See “Products Pipelines” below for additional information on the Mariner South project.

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



	Year Ended December 31,
	2014	2013	2012
Crude oil and refined products throughput (thousands of bpd)	1,233	932	724

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.

The Fort Mifflin Terminal contains two ship docks with 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, which is operated by Philadelphia Energy Solutions ("PES") under a joint venture with Sunoco. 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,
	2014	2013	2012
	(in thousands of bpd)
Crude oil throughput	154	258	293
Refined products throughput	—	—	13
Total	154	258	306

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 products pipelines.

Marcus Hook Industrial Complex

In 2013, we acquired Sunoco's Marcus Hook Industrial Complex. The acquisition included terminalling and storage assets with a capacity of approximately 3 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.

Mariner East 1 and Mariner East 2 are pipeline projects to deliver NGLs from the Marcellus and Utica Shale areas in Western Pennsylvania, West Virginia and Eastern Ohio to the Marcus Hook Industrial Complex. Mariner East 1 commenced initial operations in the fourth quarter 2014. Mariner East 2 is expected to commence operations in the fourth quarter 2016.

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 marine vessels (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. In the fourth quarter 2014, we acquired land at Eagle Point under a purchase option embedded in an existing lease with Sunoco. The tank farm has a total active storage capacity of approximately 6 million barrels and can receive crude oil and refined products via barge, pipeline and rail. The terminal can deliver via barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage 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,
	2014	2013	2012
	(in thousands of bpd)
Crude oil throughput	16	20	14
Refined products throughput	74	79	42
Total	90	99	56

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 pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and offloading rack.

Products Pipelines

We own and operate approximately 2,400 miles of products pipelines in several regions of the United States. The pipelines primarily transport refined products and NGLs in the northeast, midwest, and southwest United States to markets in these areas, as well as Ontario, Canada. These operations include our controlling financial interest in Inland, which owns approximately 350 miles of products pipeline.

The products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), and liquefied petroleum gases (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 Products Pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission ("PA PUC"), among other state regulatory agencies.

The Allegheny Access project, a products pipeline system created from both newly constructed and existing pipeline assets, is expected to commence start up operations by the end of the first quarter 2015. The pipeline will transport refined products from the Midwest to Eastern Ohio and Western Pennsylvania markets. The pipeline is able to transport up to 85,000 bpd, with the possibility to increase capacity to meet further demands.

Mariner East 1 is a pipeline project to deliver NGLs from the Marcellus Shale areas in Western Pennsylvania to Marcus Hook, Pennsylvania, which commenced initial operations in the fourth quarter 2014. Mariner East 2 is the second phase of the project, which will expand the total takeaway capacity to 345,000 barrels per day. Mariner East 1 and Mariner East 2 will deliver NGLs to our Marcus Hook Industrial Complex on the Delaware River in Pennsylvania, where it will be processed, stored and distributed to various local, domestic and waterborne markets. In addition to delivering NGLs from the Marcellus

and Utica Shale areas of Western Pennsylvania, Mariner East 2 will also deliver NGLs from the shale areas in West Virginia and Eastern Ohio. Mariner East 2 is expected to commence operations in the fourth quarter 2016.

The Mariner South pipeline provides transportation of propane and butane products from the Mont Belvieu region to the Nederland Terminal. Mariner South commenced initial operations in December 2014, with an initial capacity to transport approximately 200,000 barrels per day of natural gas liquids and other products.

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


•	Explorer Pipeline—In March 2014, we exercised rights to acquire an additional ownership in Explorer Pipeline Company ("Explorer") for $42 million, increasing the Partnership's ownership interest from 9.4 to 13.3 percent. Explorer owns approximately 1,850 miles of refined products pipelines running from the Gulf Coast of the United States to the Chicago, Illinois area.

•

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 products pipelines in each of the years presented. Average shipments represent the average revenue-generating pipeline throughput:



	Year Ended December 31,
	2014	2013	2012
Pipeline throughput (thousands of bpd)⁽¹⁾	552	571	582


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

The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the Products Pipelines affect both the demand for, and the mix of, the 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 products pipelines, summarized in the following table:



Pipeline	SXL Equity Ownership	Approximate Pipeline Mileage
Explorer Pipeline Company ⁽¹⁾	13.3%	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. An additional 3.9 percent ownership interest was purchased in the first quarter 2014.


⁽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 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 United States compete with other independent terminals on price, versatility, and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies, and distribution companies with marketing and trading activities. 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."

Products Pipelines

Generally, pipelines are the lowest-cost method for long-haul, overland movement of refined products and NGLs. 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 Products Pipelines will be built by our competitors 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 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 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 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 Integrity Management Program, identified the line segments that could impact high consequence areas, and completed a full assessment of these segments as prescribed by the regulations.

We are confident that our pipeline operations are in substantial compliance with applicable DOT regulations and comparable state requirements. However, an increase in expenditures may be needed in the future to comply with higher industry and regulatory safety standards. Such expenditures cannot be estimated accurately at this time, but we do not believe they would likely have a material adverse effect relative to our results of operations, financial position or expected cash flows.

Environmental Regulation

General

Our operations are often subject to complex federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations which govern the handling and release of crude oil and other liquid hydrocarbon materials, some of which are discussed below. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. Our management believes we are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the legislative and regulatory trend has been to place increasingly stringent limitations on activities that may affect the environment.

There are also risks of accidental releases into the environment associated with our operations, such as releases of crude oil or hazardous substances from our pipelines or storage facilities. To the extent an event is not covered by our insurance policies, such accidental releases could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental laws or regulations.

Sunoco indemnifies us for 100 percent of all losses from environmental liabilities related to the assets contributed to SXL arising prior to, and asserted within 21 years of, February 8, 2002, the date of our initial public offering ("IPO"). Sunoco's share of liability for claims asserted thereafter will decrease by 10 percent each year through the thirtieth year following the IPO date. For example, for a claim asserted during the twenty-third year after the closing of the IPO, Sunoco would be required to indemnify the Partnership for 80 percent of its loss. There is no monetary cap on this indemnification from Sunoco. In addition, this indemnification applies to the following, purchased from Sunoco subsequent to the IPO: interests in the Mesa Pipeline System, Mid-Valley, West Texas Gulf 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, 2014, 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 Acts' ("CERCLA"), also known as Superfund, definition of a "hazardous substance" and, as a result, we may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Costs for any such remedial actions, as well as any related claims, could have a material adverse effect on our maintenance capital expenditures and operating expenses to the extent not all are covered by the indemnity from Sunoco. For more information, please see "Environmental Remediation."

We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act ("RCRA"), and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during our operating activities, will in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements than non-hazardous wastes. Any changes in the regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent future contamination.

We have not been identified by any state or federal agency as a potentially responsible party in connection with the transport and/or disposal of any waste products to third-party disposal sites.

Water

Our operations can result in the discharge of regulated substances, including crude oil, 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. We have also purchased certain pipeline and terminal assets for which we assume remediation responsibilities. Our management estimates that the total aggregate cost of performing the currently anticipated assessment, monitoring, and remediation activities at these sites is not material in relation to our operations, financial position or cash flows at December 31, 2014. 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 Railroad Commission of Texas ("Texas R.R.C.") and the Pennsylvania Public Utility Commission ("PA PUC"). 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 titles to these properties are subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens for environmental contamination, taxes and other burdens, easements, or other restrictions, management believes that none of these burdens materially detract from the value of the properties or will materially interfere with their use in the operation of our business.

Employees

We have no employees. To carry out the operations of Sunoco Logistics Partners L.P., our general partner and its affiliates employed approximately 2,250 people at December 31, 2014 who provide direct support to the operations. Labor unions or associations represented approximately 1,100 of these employees at December 31, 2014.

(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 conditions that result in lower purchases of refined petroleum products;


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


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


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


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

A material decrease in demand driven by unfavorable crude oil prices could materially and adversely affect our results of operations, financial position or cash flows.

The volume of crude oil transported through our crude oil pipelines, terminal facilities and acquisition and marketing assets depends on the availability of attractively priced crude oil produced or received in the areas served by our assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to our customers, could materially reduce demand for crude oil in the these areas. In either case, the volumes of crude oil transported in our crude oil pipelines, terminal facilities and acquisition and marketing assets could decline, and it could likely be difficult to secure alternative sources of attractively priced crude supply in a timely fashion or at all. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position or cash flows could be materially and adversely affected.

A material decrease in demand resulting from unfavorable natural gas liquids (“NGLs”) prices could materially and adversely affect our results of operations, financial position, or cash flows.

Any significant and prolonged change in the actual or expected demand for NGLs could have an adverse impact on the volumes transported in our pipelines, through our terminals, or bought and sold through our acquisition and marketing assets. Changes in demand could result from additional regulatory restrictions on the extraction of NGLs that would significantly increase the cost of extraction and procurement; changes in technology affecting the mix of energy products available; or changes in laws, regulations, or costs related to exportation. Any material decrease in demand could have a material adverse effect on our results of operations, financial position, or cash flows.

Any reduction in throughput capacity available to our shippers, including our crude oil, refined products and NGLs 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, refined products and NGLs. 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, refined products and NGLs 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.

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, 2014, our consolidated balance sheet reflected $1.36 billion of goodwill and $770 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 and/or volumes.

Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and we could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.

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 crude oil, refined products and NGLs result in a risk that crude oil, refined products, NGLs, and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resource damages, personal injury, or property damage to private parties, and significant business interruption. We own or lease a number of properties that have been used to store or distribute crude oil, refined products and NGLs 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 or wells. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt.

Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens and, to a lesser extent, issuance of injunctions to limit or cease operations. We may be unable to recover these costs through increased revenues.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.

The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, the operations of our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for our services.

The U.S. Senate has considered legislation to restrict U.S. emissions of carbon dioxide and other greenhouse gases ("GHG") that may contribute to global warming and climate change. Many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce GHG emissions. The U.S. House of Representatives has previously approved legislation to establish a "cap-and-trade" program, whereby the U.S. Environmental Protection Agency ("EPA") would issue a capped and steadily declining number of tradable emissions allowances to certain major GHG emission sources so they could continue to emit GHGs into the atmosphere. The cost of such allowances would be expected to escalate significantly over time, making the combustion of carbon-based fuels (e.g., refined petroleum products, oil and natural gas) increasingly expensive. Beginning in 2011, EPA regulations required specified large domestic GHG sources to report emissions above a certain threshold occurring after January 1, 2010. Our facilities are not subject to this reporting requirement since our GHG emissions are below the applicable threshold. In addition, the EPA has proposed new regulations, under the federal Clean Air Act, that would require a reduction in GHG emissions from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. It is not possible at this time to predict how pending legislation or new regulations to address GHG emissions would impact our business. However, the adoption and implementation of federal, state, or local laws or regulations limiting GHG emissions in the U.S. could adversely affect the demand for our crude oil 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 affiliated entities and third parties in the processing of our information and data. Breaches of our security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this information, result in litigation and potential liability for us, lead to reputational damage, increase our compliance costs, or otherwise harm our business.

Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.

In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.

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, 2014, approximately 49 percent of our workforce was covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppages could have a material adverse effect on our business, financial position, results of operations or cash flows.

We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.

Certain of our joint ventures have their own governing boards, and we may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in our or the joint venture's best interests. Likewise, we may be unable to prevent actions of the joint venture.

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.

Our general partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.

Pursuant to our partnership agreement, our general partner has the ability, in its sole discretion and without the approval of the unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our general partner, including:

•the right to share in the Partnership’s profits and losses;


•	the right to share in the Partnership’s distributions;


•	the rights upon dissolution and liquidation of the Partnership;


•	whether, and the terms upon which, the Partnership may redeem the securities;


•	whether the securities will be issued, evidenced by certificates and assigned or transferred; and


•	the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.

Please see “We may issue additional common units without unitholder approval, which would dilute our unitholders' ownership interests.” below.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner has the right to transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the owner of our general partner from transferring its ownership interest in the general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of the general partner with its own appointees.

Conflicts of interest may arise between us and ETP as they are the controlling owner of our general partner, which, due to limited fiduciary responsibilities, may permit ETP and its affiliates to favor their own interests to the detriment of our unitholders.

ETP is the controlling owner of our general partner interest and owns 29.7 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. Our partnership agreement provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the unitholders, and will not constitute a breach of the partnership agreement These conflicts may include, among others, the following situations:


•	ETP and its affiliates may engage in competition with us. Neither our partnership agreement nor any other agreement requires ETP to pursue a business strategy that favors us or utilizes our assets, and our general partner may consider the interests of parties other than us, such as ETP, in resolving conflicts of interest;


•	under our partnership agreement, our general partner's fiduciary duties are restricted, and our unitholders have only limited remedies available in the event of conduct constituting a potential breach of fiduciary duty by our general partner;


•	our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash available for distribution to our unitholders and the amount received by our general partner in respect of its incentive distribution rights ("IDRs");


•	our general partner determines which costs incurred by ETP and its affiliates are reimbursable by us; and

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any additional contractual arrangements are fair and reasonable to us; and our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates.

We are a holding company. We conduct our operations through our subsidiaries and depend on cash flow from our subsidiaries to pay distributions to our unitholders and service our debt obligations.

We are a holding company. We conduct our operations through our subsidiaries. As a result, our cash flow and ability to pay distributions to our unitholders and to service our debt is dependent upon the earnings of our subsidiaries. In addition, we are dependent on the distribution of earnings, loans or other payments from our subsidiaries to us. Any payment of dividends, distributions, loans or other payments from our subsidiaries to us could be subject to statutory or contractual restrictions. Payments to us by our subsidiaries also will be contingent upon the profitability of our subsidiaries. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our unitholders or pay interest or principal on our debt securities when due.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits the general partner or its affiliates.

ETP is the controlling owner of our general partner and also owns 29.7 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, 2014, our total outstanding indebtedness was $4.15 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 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 reserves, as applicable, or the reserves of our or Sunoco Logistics Partners L.P.'s operating subsidiaries, as applicable, as they determine are necessary or appropriate. As a result, we and Sunoco Logistics Partners L.P. do not have the same flexibility as corporations or other entities that do not pay dividends or that have complete flexibility regarding the amounts they will distribute to their equity holders. Although our payment obligations to our partners are subordinate to our payment obligations on our debt, the timing and amount of our quarterly distributions to our partners could significantly reduce the cash available to pay the principal, premium (if any), and interest on our notes.

Rising short-term interest rates could increase our financing costs and reduce the amount of cash we generate.

As of December 31, 2014, we had $185 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 downgrade in ETP's credit ratings could also result in a downgrade in our credit ratings. Ratings from credit agencies are not recommendations to buy, sell or hold our securities, and each rating should be evaluated independently of any other rating.

TAX RISKS TO OUR COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity level taxation by individual states. If the Internal Revenue Service ("IRS") treats us as a corporation or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. Despite the fact that we are a limited partnership under Pennsylvania law, we would be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. We believe that we satisfy the qualifying income requirement based on our current operations. Failing to meet this requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Therefore, treatment of us as a corporation would result in a material reduction in anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our common Units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our case available for distribution to our unitholders

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 common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts ("IRAs"), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or non-U.S. person, you should consult your tax advisor before investing in our common units.

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 35 states, most of which impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all United States federal, state and local tax returns.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our Unitholders.

We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

Even though we (as a partnership for U.S. federal income tax purposes) are not subject to U.S. federal income tax, some of our operations are currently conducted through subsidiaries that are organized as corporations for U.S. federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for U.S. federal income tax purposes, is subject to corporate-level U.S. federal income taxes which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our Unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our Unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

A Unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our public Unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our Unitholders and our General Partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain Unitholders and our General Partner, which may be unfavorable to such Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of our Unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders. It also could affect the amount of gain on the sale of common units by our Unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our Unitholders without the benefit of additional deductions.



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 products pipeline in Wellington, Ohio. In connection with this release, the Pipeline Hazardous Material Safety Administration ("PHMSA") issued a Corrective Action Order under which the Partnership is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. The Partnership also entered into an Order on Consent with the Environmental Protection Agency ("EPA") regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. The Partnership has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. 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 2015. The timing or outcome of this matter cannot be reasonably determined at this time. However, the Partnership does not expect there to be a material impact to its results of operations, cash flows or financial position.

In 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 25, 2015, there were 64 holders of record of our common units. These holders of record included the general partner with 67.1 million common units registered in its name, and Cede & Co., a clearing house for stock transactions, with the majority of the remaining 162.5 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.

On June 12, 2014, the Partnership completed a two-for-one split of its common units, which resulted in the issuance of one additional common unit for every one common unit owned. All unit and per unit information included in this report are presented on a post-split basis. The high and low sales price ranges (composite transactions) and distributions declared (per unit), by quarter, for 2014 and 2013 were as follows:



	2014						2013
	Unit Price				Declared Distributions		Unit Price				Declared Distributions
Quarter	High		Low		Declared Distributions		High		Low		Declared Distributions
1^st	$	45.76	$	36.40	$	0.3475	$	34.22	$	25.17	$	0.2863
2^nd	$	47.82	$	43.01	$	0.3650	$	32.88	$	28.88	$	0.3000
3^rd	$	51.45	$	42.20	$	0.3825	$	34.11	$	29.30	$	0.3150
4^th	$	52.47	$	35.61	$	0.4000	$	38.04	$	32.41	$	0.3312

Within 45 days after the end of each quarter, we distribute all cash on hand at the end of the quarter, less reserves established by our general partner in its discretion. This is defined as "available cash" in the partnership agreement. Our general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. We will make minimum quarterly distributions of $0.075 per common unit, to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

If cash distributions exceed $0.0833 per unit in a quarter, our general partner will receive increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as "incentive distributions." The amounts shown in the table under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and our unitholders in any available cash from operating surplus that is distributed up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until the available cash that is distributed reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

There is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we are prohibited from making any distributions to our unitholders if it would cause an event of default, or an event of default exists under the credit facilities or the senior notes (see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources").

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	$0.0750	2	%		98%
First Target Distribution	up to $0.0833	2	%		98%
Second Target Distribution	above $0.0833
Second Target Distribution	up to $0.0958	15	%	⁽¹⁾	85%
Third Target Distribution	above $0.0958
Third Target Distribution	up to $0.2638	37	%	⁽¹⁾	63%
Thereafter	above $0.2638	50	%	⁽¹⁾	50%


⁽¹⁾	Includes 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,						Period from Acquisition, October 5, 2012 to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	2014			2013						Period from January 1, 2012 to October 4, 2012			2011			2010
	(in millions, except per unit data)									(in millions, except per unit data)
Income Statement Data:
Revenues:
Sales and other operating revenue:
Unaffiliated customers	$	17,018		$	15,073		$	2,989		$	9,460		$	10,473		$	6,691
Affiliates	1,070			1,566			200			461			432			1,117
Gain on divestment and related matters	—			—			—			11			—			—
Total revenues	$	18,088		$	16,639		$	3,189		$	9,932		$	10,905		$	7,808
Operating income ⁽¹⁾	$	367		$	560		$	159		$	460		$	423		$	271
Other income ⁽²⁾	$	25		$	21		$	5		$	18		$	13		$	30
Income before income tax expense	$	325		$	504		$	150		$	413		$	347		$	356
Net Income	$	300		$	474		$	142		$	389		$	322		$	348
Net Income attributable to noncontrolling interests	(9		)	(11		)	(3		)	(8		)	(9		)	(2		)
Net Income attributable to Sunoco Logistics Partners L.P.	$	291		$	463		$	139		$	381		$	313		$	346
Net Income attributable to Sunoco Logistics Partners L.P. per Limited Partner unit: ⁽³⁾
Basic	$	0.52		$	1.63		$	0.55		$	1.57		$	1.28		$	1.56
Diluted	$	0.51		$	1.63		$	0.55		$	1.57		$	1.27		$	1.56
Cash distributions per unit to Limited Partners: ^{(3) (4)}
Paid	$	1.43		$	1.17		$	0.26		$	0.66		$	0.81		$	0.75
Declared	$	1.50		$	1.23		$	0.27		$	0.71		$	0.82		$	0.77
Other Data:
Adjusted EBITDA ⁽⁵⁾	$	971		$	871		$	219		$	591		$	573		$	399
Distributable Cash Flow ⁽⁵⁾	$	750		$	660		$	163		$	439		$	388		$	242

⁽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. ("ETP"), 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, Bayview Refining Company, LLC ("Bayview"), SunVit Pipeline LLC ("SunVit"), 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 or formation. 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⁾	In December 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. In June 2014, a two-for-one split was completed, which resulted in the issuance of one additional common unit for every one unit owned. All unit and per unit information is presented on a post-split basis.


⁽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,						Period from Acquisition, October 5, 2012 to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	2014			2013						Period from January 1, 2012 to October 4, 2012			2011			2010
	(in millions)									(in millions)
Net Income	$	300		$	474		$	142		$	389		$	322		$	348
Interest expense, net	67			77			14			65			89			73
Depreciation and amortization expense	296			265			63			76			86			64
Impairment charge and other related matters	258			—			—			9			31			3
Provision for income taxes	25			30			8			24			25			8
Non-cash compensation expense	16			14			2			6			6			5
Unrealized losses/(gains) on commodity risk management activities	(17		)	(1		)	(3		)	6			(2		)	2
Amortization of excess equity method investment	2			2			—			—			—			—
Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes	24			20			5			16			16			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	971			871			219			591			573			399
Interest expense, net	(67		)	(77		)	(14		)	(65		)	(89		)	(73		)
Provision for current income taxes ⁽¹⁾	(29		)	(24		)	(10		)	(24		)	(27		)	(8		)
Amortization of fair value adjustments on long-term debt	(14		)	(23		)	(6		)	—			—			—
Distributions versus Adjusted EBITDA of unconsolidated affiliates	(35		)	(27		)	(3		)	(25		)	(17		)	(36		)
Maintenance capital expenditures	(76		)	(53		)	(21		)	(29		)	(42		)	(37		)
Distributable Cash Flow attributable to noncontrolling interests	(12		)	(16		)	(2		)	(9		)	(10		)	(3		)
Contributions attributable to acquisition from affiliate	12			9			—			—			—			—
Distributable Cash Flow ⁽¹⁾	$	750		$	660		$	163		$	439		$	388		$	242


⁽¹⁾	During the third quarter 2014, we changed our definition of Distributable Cash Flow to conform to the presentation utilized by ETP. This change did not have a material impact on our Distributable Cash Flows. Prior period amounts have been recast to conform to current presentation.



	Successor									Predecessor
	Year Ended December 31,						Period from Acquisition, October 5, 2012 to December 31, 2012			Period from January 1, 2012 to October 4, 2012			Year Ended December 31,
	2014			2013						Period from January 1, 2012 to October 4, 2012			2011			2010
	(in millions)									(in millions)
Net cash provided by operating activities	$	566		$	749		$	280		$	411		$	430		$	341
Interest expense, net	67			77			14			65			89			73
Amortization of bond premium, financing fees and bond discount	12			22			6			(2		)	(2		)	(2		)
Deferred income tax (expense) benefit	4			(6		)	2			—			2			—
Regulatory matters excluded from Adjusted EBITDA	—			—			—			10			(11		)	—
Claim for (recovery of) environmental liability	—			—			(13		)	14			—			—
Equity in earnings of unconsolidated affiliates	25			21			5			15			12			24
Distributions from unconsolidated affiliates	(14		)	(14		)	(6		)	(5		)	(11		)	(12		)
Net change in working capital pertaining to operating activities	258			(20		)	(91		)	29			37			(57		)
Unrealized losses/(gains) on commodity risk management activities	(17		)	(1		)	(3		)	6			(2		)	2
Amortization of excess equity method investment	2			2			—			—			—			—
Proportionate share of unconsolidated affiliates’ interest, depreciation and provision for income taxes	24			20			5			16			16			24
Non-cash accrued liability adjustment	—			(10		)	—			—			—			—
Adjustments to commodity hedges resulting from "push-down" accounting	—			—			(12		)	—			—			—
Provision for income taxes	25			30			8			24			25			8
Other	19			1			24			8			(12		)	(2		)
Adjusted EBITDA	$	971		$	871		$	219		$	591		$	573		$	399

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,						Period from Acquisition, October 5, 2012 to December 31, 2012 ⁽³⁾			Period from January 1, 2012 to October 4, 2012 ⁽³⁾			Year Ended December 31,
	2014 ⁽¹⁾			2013 ⁽²⁾						Period from January 1, 2012 to October 4, 2012 ⁽³⁾			2011 ⁽⁴⁾			2010 ⁽⁵⁾
	(in millions)									(in millions)
Cash Flow Data:
Net cash provided by operating activities	$	566		$	749		$	280		$	411		$	430		$	341
Net cash used in investing activities	$	(2,866	)	$	(957	)	$	(139	)	$	(224	)	$	(609	)	$	(426	)
Net cash provided by (used in) financing activities	$	2,362		$	244		$	(140	)	$	(190	)	$	182		$	85
Capital expenditures:
Expansion ⁽⁶⁾	$	2,346		$	851		$	118		$	206		$	171		$	137
Maintenance ⁽⁷⁾	70			46			21			29			42			37
Acquisitions	391			60			—			—			396			252
Investments in joint venture interests	$	42		$	—		$	—		$	—		$	—		$	—
Total capital expenditures	$	2,849		$	957		$	139		$	235		$	609		$	426

⁽¹⁾

Cash flows related to expansion capital expenditures in 2014 included projects to: invest in the previously announced Mariner and Allegheny Access projects; invest in our crude oil infrastructure by increasing our pipeline capabilities through previously announced expansion capital projects in Texas and Oklahoma; expand the service capabilities of our refined products and NGLs acquisition and marketing business; and upgrade the service capabilities at our bulk marine terminals. Cash flows related to acquisitions in 2014 included $65 million related to a crude oil acquisition and marketing business and a controlling financial interest in a related rail facility, and $325 million related to the acquisition of additional ownership interest in a consolidated subsidiary.

⁽²⁾

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 Industrial Complex from Sunoco for $60 million in 2013.

⁽³⁾

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.

⁽⁴⁾

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 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").

⁽⁵⁾

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 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.


⁽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,
	2014		2013		2012		2011		2010
	(in millions)						(in millions)
Balance Sheet Data (at period end):
Net properties, plants and equipment	$	8,849	$	6,519	$	5,623	$	2,522	$	2,128
Total assets	$	13,644	$	11,897	$	10,361	$	5,477	$	4,188
Total debt	$	4,260	$	2,503	$	1,732	$	1,698	$	1,229
Total Sunoco Logistics Partners L.P. Equity	$	6,678	$	6,204	$	6,072	$	1,096	$	965
Noncontrolling interests	60		121		123		98		77
Total equity	$	6,738	$	6,325	$	6,195	$	1,194	$	1,042



	Successor						Predecessor
	Year Ended December 31,				Period from Acquisition, October 5, 2012 to December 31, 2012		Period from January 1, 2012 to October 4, 2012		Year Ended December 31,
	2014		2013						2011		2010
Operating Data:
Crude Oil Pipelines ⁽¹⁾
Pipeline throughput (thousands of barrels per day ("bpd")) ⁽²⁾	2,125		1,866		1,584		1,546		1,587		1,183
Pipeline revenue per barrel (cents)	71.6		72.7		75.6		68.0		55.0		50.7
Crude Oil Acquisition and Marketing ⁽³⁾
Crude oil purchases (thousands of bpd)	873		749		669		674		663		638
Gross profit per barrel purchased (cents)⁽⁴⁾	60.5		94.9		142.5		95.1		68.1		23.4
Average crude oil price (per barrel)	$	92.92	$	98.00	$	88.20	$	96.20	$	95.14	$	79.55
Terminal Facilities ⁽⁵⁾
Terminal throughput (thousands of bpd)
Refined products terminals	414		431		451		499		492		488
Nederland terminal	1,233		932		787		703		757		729
Refinery terminals	288		397		411		369		443		465
Products Pipelines ⁽¹⁾
Pipeline throughput (thousands of bpd) ⁽⁶⁾	552		571		601		565		522		468
Pipeline revenue per barrel (cents)	88.1		62.5		63.0		62.2		68.3		70.0


⁽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. In the fourth quarter 2014, we adjusted our classification of certain operating expenses and selling, general and administrative expenses to conform to the presentation utilized by ETP. All prior period amounts, including gross profit per barrel purchased, have been recast to conform to current presentation.


⁽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⁾

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.



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 35 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, 2014, 2013 and 2012 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 67.1 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 acquisition and marketing assets to maximize value, 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

We completed four acquisitions for a total of $466 million during the three-year period ended December 31, 2014:

2014 Acquisitions

•

West Texas Gulf Pipe Line Company - In December 2014, we acquired an additional 28.3 percent ownership interest in the West Texas Gulf Pipe Line Company ("West Texas Gulf") from Chevron Pipe Line Company, increasing our controlling financial interest to 88.6 percent. The remaining noncontrolling interest in West Texas Gulf was acquired in January 2015. The pipeline continues to be reported in the Crude Oil Pipelines segment.

•

EDF Trading - In May 2014, we acquired a crude oil purchasing and marketing business from EDF Trading North America, LLC ("EDF"). The purchase consisted of a crude oil acquisition and marketing business and related assets which handle 20 thousand barrels per day. The acquisition also included a promissory note that was convertible to an equity interest in a rail facility (see Price River Terminal, below). The acquisition is included in the Crude Oil Acquisition and Marketing segment.

•

Price River Terminal - In May 2014, we acquired a 55 percent economic and voting interest in Price River Terminal, LLC ("PRT"), a rail facility in Wellington, Utah. The terms of the acquisition provide PRT’s noncontrolling interest holders the option to sell their interests to the Partnership at a price defined in the purchase agreement. As a result, the noncontrolling interests attributable to PRT are excluded from the Partnership's total equity and are instead reflected as redeemable interests in the condensed consolidated balance sheet as of December 31, 2014. As the Partnership acquired a controlling financial interest in PRT, the entity is reflected as a consolidated subsidiary of the Partnership from the acquisition date and is included in the Crude Oil Acquisition and Marketing segment.

2013 Acquisition

•

Marcus Hook Industrial Complex - In the second quarter 2013, we acquired Sunoco's Marcus Hook Industrial Complex and related assets (the "Marcus Hook Industrial Complex"). 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 Industrial Complex 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.

Growth Capital Program

In 2014, we invested $2.5 billion 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 the previously announced Mariner and Allegheny Access projects; invest in our crude oil infrastructure by increasing pipeline capabilities through previously announced expansion capital projects in Texas and Oklahoma; expand the service capabilities of our refined products and NGLs acquisition and marketing business; and upgrade the service capabilities at our bulk marine terminals. We also increased activity in the pipeline transportation, storage, and acquisition and marketing of NGLs in the northeastern United States with additional pipeline throughput on the delivery of ethane from the Marcellus Shale Basin to Ontario and activities at our Marcus Hook Industrial Complex. Operational results from these activities have been included in our Products Pipelines and Terminal Facilities segments. We will continue to expand our NGL platform through previously announced growth projects that are expected to commence operations throughout 2015 and 2016.

During 2015, we expect to invest approximately $2 billion in expansion capital expenditures related to organic growth, excluding acquisitions and investment in joint venture interests. This includes spending to capture more value from existing assets such as the Marcus Hook Industrial Complex, our crude pipelines, our bulk marine terminals and our patented blending technology. Expansion capital expenditures in 2015 will also include continued progress on our previously announced growth projects:

Mariner East 1 and Mariner East 2

Mariner East 1 is a pipeline project to deliver NGLs from the Marcellus Shale areas in Western Pennsylvania to Marcus Hook, Pennsylvania, which commenced initial operations in the fourth quarter 2014. Mariner East 2 is the second phase of the project, which will expand the total takeaway capacity to 345,000 barrels per day. In addition to delivering NGLs from the Marcellus and Utica Shale areas of Western Pennsylvania, Mariner East 2 will also deliver NGLs from the shale areas in West Virginia and Eastern Ohio. Mariner East 1 and Mariner East 2 will deliver NGLs to our Marcus Hook Industrial Complex on the Delaware River in Pennsylvania, where it will be processed, stored and distributed to various local, domestic and waterborne markets. Mariner East 2 is expected to commence operations in the fourth quarter 2016.

Permian Express 2

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 third quarter 2015.

Permian Longview and Louisiana Extension

This project will enable us to provide takeaway capacity for approximately 100,000 additional barrels per day out of the basin at Midland to be transported to the Longview area, as well as destinations in Louisiana, utilizing a combination of our proprietary crude oil system, as well as third party pipelines. The project is expected to commence operations in mid-2016.

Delaware Basin Extension

The Delaware Basin Extension project will provide shippers with new takeaway capacity from the rapidly growing Delaware Basin area in New Mexico and West Texas to Midland, Texas. The project will consist of approximately 125 miles of new build pipeline and is anticipated to have initial capacity to transport approximately 100,000 barrels per day. The pipeline is expected to be operational in the first half 2016.

Allegheny Access

The Allegheny Access project will provide transport of refined products from the Midwest to markets in Eastern Ohio and Western Pennsylvania. The pipeline is expected to commence start up operations by the end of the first quarter 2015.

Conservative Capital Structure

Our goal is to maintain substantial liquidity and a conservative capital structure. Sunoco Logistics Partners Operations L.P. (the "Operating Partnership"), our wholly-owned subsidiary, maintains a $1.50 billion Credit Facility, which contains an "accordion" feature, that, under certain conditions, may increase to $2.25 billion.

During 2014, we issued 18.0 million common units for net proceeds of $839 million in connection with an overnight equity offering and activity under our at-the-market equity offering program ("ATM program"). We also issued $2.0 billion of long-term debt in connection with senior notes offerings.

We will maintain our conservative capital structure by utilizing a combination of our operating cash flows and debt and equity issuances to finance our future growth.

Cash Distribution Increases

As a result of our continued growth, our general partner increased our cash distributions to limited partners in all quarters in the three years ended December 31, 2014. For the quarter ended December 31, 2014, the distribution increased to $0.40 per common unit ($1.60 annualized). The distribution for the fourth quarter 2014 was paid on February 13, 2015.

Results of Operations



	Successor										Predecessor
	Year Ended December 31, 2014		Year Ended December 31, 2013		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⁾
	(in millions, except per unit data)										(in millions, except per unit data)
Statements of Income
Sales and other operating revenue:
Unaffiliated customers	$	17,018	$	15,073	$	3,907	$	11,166	$	2,989	$	9,460
Affiliates	1,070		1,566		381		1,185		200		461
Gain on divestment and related matters	—		—		—		—		—		11
Total revenues	18,088		16,639		4,288		12,351		3,189		9,932
Cost of products sold ⁽²⁾	16,853		15,574		4,040		11,534		2,885		9,214
Operating expenses	196		148		31		117		58		122
Selling, general and administrative expenses ⁽²⁾	118		92		22		70		24		61
Depreciation and amortization expense	296		265		69		196		63		76
Impairment charge and other related matters	258		—		—