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GLOBAL PARTNERS LP 10-K 2011

Table of Contents

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, 2010

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                    to

Commission file number 001-32593

Global Partners LP
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  74-3140887
(I.R.S. Employer Identification No.)

P.O. Box 9161
800 South Street
Waltham, Massachusetts 02454-9161
(Address of principal executive offices, including zip code)

(781) 894-8800
(Registrant's telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:

Title of each class   Name of each exchange on which registered
Common Units representing limited partner interests   New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act:

None

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No 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 o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes o    No o

         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 registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.:

  Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o   Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         The aggregate market value of common units held by non-affiliates of the registrant (treating directors and executive officers of the registrant's general partner and holders of 10% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of June 30, 2010 was approximately $188,854,670 based on a price per common unit of $22.49, the price at which the common units were last sold as reported on the New York Stock Exchange on such date.

         As of March 8, 2011, 21,580,563 common units were outstanding.


Table of Contents

TABLE OF CONTENTS

PART I

       
 

Items 1. and 2.

 

Business and Properties

  3
 

Item 1A.

 

Risk Factors

  17
 

Item 1B.

 

Unresolved Staff Comments

  41
 

Item 3.

 

Legal Proceedings

  41
 

Item 4.

 

[Removed and Reserved]

  42

PART II

       
 

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

  43
 

Item 6.

 

Selected Financial Data

  45
 

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

  48
 

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

  77
 

Item 8.

 

Financial Statements and Supplementary Data

  79
 

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

  79
 

Item 9A.

 

Controls and Procedures

  79
 

Item 9B.

 

Other Information

  82

PART III

       
 

Item 10.

 

Directors, Executive Officers and Corporate Governance

  83
 

Item 11.

 

Executive Compensation

  87
 

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  113
 

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  115
 

Item 14.

 

Principal Accounting Fees and Services

  121

PART IV

       
 

Item 15.

 

Exhibits and Financial Statement Schedules

  122

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Forward-Looking Statements

        Some of the information contained in or incorporated by reference in this Annual Report on Form 10-K may contain forward-looking statements. Forward-looking statements do not relate strictly to historical or current facts and include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words "may," "believe," "should," "could," "expect," "anticipate," "plan," "intend," "estimate," "continue," "will likely result," or other similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us are also forward-looking statements. Forward-looking statements are not guarantees of performance. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks, many of which are beyond our control, which may cause future results to be materially different from the results stated or implied in this document. These risks and uncertainties, which could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders, include, among other things:

    We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution or maintain distributions at current levels following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

    A significant decrease in demand for refined petroleum products in the areas served by our storage facilities and/or our retail gasoline business could reduce our ability to make distributions to our unitholders.

    Our sales of home heating oil and residual oil could be significantly reduced by conversions to natural gas.

    Erosion of the value of the Mobil brand could adversely affect our gasoline sales and customer traffic.

    Our gas station and convenience store business could expose us to an increase in consumer litigation and result in an unfavorable outcome or settlement of one or more lawsuits where insurance proceeds are insufficient or otherwise unavailable.

    Our gasoline sales could be significantly reduced by a reduction in demand due to new technologies and alternative fuel sources, such as electric, hybrid or battery powered motor vehicles.

    Changes to government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our gasoline sales.

    Warmer weather conditions could adversely affect us.

    Our risk management policies cannot eliminate all commodity risk. In addition, any noncompliance with our risk management policies could result in significant financial losses.

    Our results of operations are influenced by the overall forward market for refined petroleum products.

    Increases and/or decreases in the prices of refined petroleum products may adversely impact the amount of borrowing available for working capital under our credit agreement, which credit agreement has borrowing base limitations and advance rates.

    We are exposed to trade credit risk in the ordinary course of our business activities.

    We are exposed to risk associated with our trade credit support in the ordinary course of our business activities.

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    The condition of credit markets may adversely affect us.

    Due to our lack of asset and geographic diversification, adverse developments in the terminals that we use or in our operating areas could reduce our ability to make distributions to our unitholders.

    A serious disruption to our information technology systems could significantly limit our ability to manage and operate our business efficiently.

    We are exposed to performance risk in our supply chain.

    Our retail gasoline business and terminal operations are subject to both federal and state environmental and non-environmental regulations which could have a material adverse effect on such businesses.

    Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of unitholders.

    Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or to remove our general partner without the consent of the holders of at least 662/3% of the outstanding units (including units held by our general partner and its affiliates), which could lower the trading price of our common units.

    Our tax treatment depends on our status as a partnership for federal income tax purposes.

    Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

        Additional information about risks and uncertainties that could cause actual results to differ materially from forward-looking statements is contained in Item 1A, "Risk Factors" in this Annual Report on Form 10-K.

        All forward-looking statements included in this Annual Report on Form 10-K and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date of this Form 10-K, and we expressly disclaim any obligation or undertaking to update these statements to reflect any change in our expectations or beliefs or any change in events, conditions or circumstances on which any forward-looking statement is based.


Available Information

        We make available free of charge through our website, www.globalp.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish such material with the Securities and Exchange Commission ("SEC"). These documents are also available at the SEC's website at www.sec.gov. Our website also includes our Code of Business Conduct and Ethics, our Governance Guidelines and the charters of our Audit Committee and Compensation Committee.

        A copy of any of these documents will be provided without charge upon written request to the General Counsel, Global Partners LP, P.O. Box 9161, 800 South Street, Suite 200, Waltham, MA 02454; fax (781) 398-4165.

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PART I

        References in this Annual Report on Form 10-K to "Global Partners LP," "Partnership," "we," "our," "us" or like terms refer to Global Partners LP and its subsidiaries. References to "our general partner" refer to Global GP LLC.

Items 1. and 2.    Business and Properties.

Overview

        We are a publicly traded Delaware limited partnership formed in March 2005. We have five operating subsidiaries: Global Companies LLC, its subsidiary, Glen Hes Corp., Global Montello Group Corp. ("GMG"), Chelsea Sandwich LLC and Global Energy Marketing LLC ("Global Energy") (the five operating subsidiaries, collectively, the "Companies"). The Companies (other than Glen Hes Corp.) are wholly owned by Global Operating LLC, our wholly owned subsidiary. GMG conducts our end user business, including certain aspects of our retail gasoline business. Global Energy was formed to conduct our natural gas operations and commenced operations in January 2010. In addition, GLP Finance Corp. ("GLP Finance") is our wholly owned subsidiary. GLP Finance has no material assets or liabilities. Its activities will be limited to co-issuing debt securities and engaging in other activities incidental thereto. Our general partner manages our operations and activities and employs our officers and substantially all of our personnel.

        We own, control or have access to one of the largest terminal networks of refined petroleum products in Massachusetts, Maine, Connecticut, Vermont, New Hampshire, Rhode Island, New York, New Jersey and Pennsylvania (collectively, the "Northeast"). We are one of the largest wholesale distributors of gasoline, distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels (such as ethanol) to wholesalers, retailers and commercial customers in the New England states and New York. We own and supply fuel to 190 Mobil-branded retail gas stations (38 leased properties and 152 fee properties) in New England and supply Mobil-branded fuel to an additional 31 independently-owned stations. In 2010, we sold approximately $7.8 billion of refined petroleum products and small amounts of natural gas and renewable fuels. In addition, we had other revenues of approximately $16.1 million, primarily from convenience store sales at our directly operated stores and gas station rental income. In 2010, we owned, leased or maintained dedicated storage facilities at 24 refined petroleum product bulk terminals, each with the capacity of more than 50,000 barrels, including 23 located throughout the Northeast, that are supplied primarily by marine transport, pipeline, rail or truck and that collectively have approximately 10.2 million barrels of storage capacity. We also have throughput, exchange or other supply agreements at more than 50 bulk terminals and inland storage facilities.

        We purchase our refined petroleum products primarily from domestic and foreign refiners, major and independent oil companies and trading companies and sell these products in two segments, Wholesale and Commercial. In 2010, our Wholesale sales accounted for approximately 93% of our total sales and our Commercial sales accounted for approximately 7%.

        As demand for some of our refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally greater during the winter months, sales are generally higher during the first and fourth quarters of the calendar year which may result in significant fluctuations in our quarterly operating results. The increase in the non-weather sensitive components of our business helps to partially offset the economic impact that warmer weather conditions may have on our home heating oil and residual oil sales. Portions of our heating oil and residual oil are sold on a forward fixed price basis. In 2010, our volume in transportation fuels, which represents a growing portion of our sales, exceeded our heating oil volumes.

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Business Strategies

        Our primary business objective is to increase distributable cash flow per unit by continuing to execute the following business strategies:

    Expand Assets and Marketing Businesses Within and Beyond Our Core Northeast Market.  We pursue strategic and accretive acquisitions of assets and marketing businesses of refined petroleum products including, without limitation, gasoline, other transportation fuels and heating oil, as well as natural gas, within our existing area of operations and in new geographic areas. We pursue strategic and accretive acquisitions of upstream or downstream assets and businesses and transportation assets and businesses related thereto. We target assets or businesses with (1) terminal and/or retail gasoline assets, (2) a marketing division that has, among other attributes, consistent cash flow and stable customer lists or (3) a combination of these attributes. We assign value to the marketing opportunities associated with these assets and businesses. Because of our interest in purchasing marketing businesses as well as physical assets, we believe we have a competitive advantage over bidders interested in purchasing only physical assets. In addition, we seek strategic relationships with companies that are looking to outsource their wholesale marketing business, as these opportunities allow us to leverage our strengths in marketing infrastructure and credit fundamentals. We currently have marketing arrangements with two major suppliers of unbranded gasoline as well as two distillate suppliers for several northeastern states.

    Pursue Organic Expansions and Improvements.  We focus on improved returns through terminal expansions, product expansions, such as natural gas and renewable fuels, and operating efficiencies.

    Serve as a Preferred Supplier to Our Customers.  We believe that our customers value dependability and quality of supply. We strive to maintain a level of inventory to ensure that the supply needs of our customers are always satisfied. During periods of product shortages, we have historically succeeded in sustaining a supply of product sufficient to meet the needs of our customers. We own, control or have access to bulk terminals and inland storage facilities that are strategically located for ease of access by our customers. Additionally, we satisfy specific customer needs by customizing our products, such as diesel and home heating oil, by blending and injecting additives.

    Focus on Credit Fundamentals of Our Customers.  We manage our trade credit exposure through conservative management practices, such as:

    pre-approving customers up to certain credit limits;

    seeking secondary sources of repayment for trade credit, such as letters of credit or guarantees;

    not offering to extend credit as a marketing tool to attract customers; and

    placing most of our customers on automatic debit systems for payment.

      As a result of these practices, in each of the past five years, the amount of account receivables that we wrote off was insignificant as a percentage of sales.

    Minimize Our Exposure to Commodity Price Volatility.  We actively manage our business to minimize commodity price exposure by using hedging techniques. We seek to maintain a position that is substantially balanced between purchases and sales by establishing an offsetting sales position with a positive margin each time we commit to purchase a volume of product.

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Recent Developments

        Retail Gas Stations/Fuel Supply Acquisition—On September 30, 2010, we completed our acquisition of retail gas stations and supply rights from ExxonMobil Corporation ("ExxonMobil") for cash consideration of approximately $202.3 million, plus the assumption of certain environmental liabilities. We acquired 190 Mobil-branded retail gas stations located in Massachusetts, New Hampshire and Rhode Island. As of December 31, 2010, of the 190 stations, 41 were directly operated on our behalf by our management agent, Alliance Energy LLC ("Alliance"), an experienced retail operator, and 149 were dealer operated subject to existing franchise agreements assigned to and assumed by us. Additionally, we acquired the right to supply Mobil-branded fuel to such stations and to 31 Mobil-branded stations that are owned and operated by independent dealers in these states. We outsourced the day-to-day management and operations of these 221 locations to Alliance. Alliance is approximately 95% owned by members of the Slifka family, who also own our general partner.

        The acquisition expands our wholesale supply business and adds vertical integration to our transportation fuel business. The stations sold approximately 370 million gallons of gasoline and diesel fuel in 2009. Initially, we intend to continue operating the stations under the Mobil brand, although we have the right to rebrand the stations to another major gasoline brand or operate the stations on an unbranded basis. We initially financed the acquisition with borrowings under our credit agreement. See Note 5 of Notes to Consolidated Financial Statements and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—ExxonMobil Acquisition" for additional information related to the transaction.

        Acquisition of Warex Terminals—On June 2, 2010, we completed our acquisition of three refined petroleum products terminals located in Newburgh, New York from Warex Terminals Corporation (the "Warex Terminals") for cash consideration of $46.0 million, plus the assumption of certain environmental liabilities. We believe the acquisition strengthens our presence along the Hudson River in southeastern New York and enhances terminal operating efficiencies with our neighboring facility. See Note 5 of Notes to Consolidated Financial Statements for additional information related to the acquisition.

        Ethanol and Rail Expansion Project—In October 2010, we completed an ethanol and rail expansion project that adds 180,000 barrels of ethanol storage at our refined petroleum product terminal in Albany, New York. The project, which became operational in October 2010, was jointly developed with Canadian Pacific Railway Limited and includes modifications that enable the terminal to schedule the delivery of 80-car trains of ethanol and allows ethanol to be shipped directly on a single rail line from the Midwest. Beyond supplying our own business, we further invested in our Albany terminal having installed a marine vapor recovery system for barge-loading of ethanol and gasoline at the dock and expanded the rack to allow for additional ethanol and gasoline sales. We believe the supply efficiencies gained through this project position us to be a premier cost effective supplier of gasoline and ethanol to the Northeast. In December 2010, the U.S. Volumetric Ethanol Excise Tax Credit, which had been authorized through December 31, 2010, was extended for one year. In a separate and complementary project, we are converting two distillate storage tanks to gasoline storage at the Albany facility. These initiatives, combined with the return to service of three previously out-of-service tanks, increased the total storage capacity of our Albany terminal to approximately 1.2 million barrels, up from 737,000 barrels when we acquired the terminal in May 2007.

        Public Offerings of Common Units—On March 19, 2010, we completed a public offering of 3,910,000 common units at a price of $22.75 per common unit. Net proceeds were approximately $84.6 million, after deducting underwriting fees and offering expenses. On November 16, 2010, we completed a public offering of 1,955,000 common units at a price of $25.57 per common unit. Net proceeds were approximately $47.7 million, after deducting underwriting fees and offering expenses. On February 8, 2011, we completed a public offering of 2,645,000 common units at a price of $27.60 per common unit.

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Net proceeds were approximately $69.7 million, after deducting underwriting fees and offering expenses. We used the net proceeds from each of these offerings to reduce indebtedness outstanding under our credit agreement. See Notes 15 and 21 of Notes to Consolidated Financial Statements for additional information related to the public offerings.

        Conversion of Subordinated Units—Subsequent to December 31, 2010, based upon meeting certain distribution and performance tests provided in our partnership agreement, all 5,642,424 subordinated units have converted to common units. See Note 21, "Subsequent Events," of Notes to Consolidated Financial Statements included elsewhere in this report.

Product Sales

        We sell our refined petroleum products in two segments, Wholesale and Commercial. The majority of the refined petroleum products we sell can be grouped into three categories: gasoline, distillates and residual oil. In addition, our other operating segment includes convenience store sales at our directly operated stores and gas station rental income. In 2010, gasoline, distillates and residual oil accounted for approximately 60%, 34% and 6%, respectively, of our total volume sold.

        Gasoline.    We sell grades of unbranded and Mobil-branded gasoline that comply with seasonal and geographical requirements in the areas in which we market. Gasoline sales accounted for approximately 60%, 51% and 50% of total sales for the years ended December 31, 2010, 2009 and 2008, respectively.

        Distillates.    Distillates are divided into home heating oil, diesel and kerosene. In 2010, sales of home heating oil, diesel and kerosene accounted for approximately 65%, 32% and 3%, respectively, of our total volume of distillates sold. Distillate sales accounted for approximately 35%, 44% and 46% of total sales for the years ended December 31, 2010, 2009 and 2008, respectively.

        We sell generic home heating oil and Heating Oil Plus™, our proprietary premium branded heating oil. Heating Oil Plus™ is electronically blended at the delivery facility. In 2010, approximately 12% of the volume of home heating oil we sold to wholesale resellers was Heating Oil Plus™. In addition, we sell the additive used to create Heating Oil Plus™ to some wholesale resellers, make injection systems available to them and provide technical support to assist them with blending. We also educate the sales force of our customers to better prepare them for marketing our products to their customers.

        We sell generic diesel and Diesel One®, our proprietary premium diesel fuel product. We offer marketing and technical support for those customers who purchase Diesel One®. In 2010, approximately 38% of the volume of diesel we sold to wholesale resellers was Diesel One®.

        Residual Oil.    We are one of three primary residual oil marketers in the Northeast. We specially blend residual oil for users in accordance with their individual power plant specifications. Residual oil sales accounted for approximately 5%, 5% and 4% of total sales for the years ended December 31, 2010, 2009 and 2008, respectively.

        We had one customer, ExxonMobil, who accounted for approximately 19%, 22% and 20% of our total sales for the years ended December 31, 2010, 2009 and 2008, respectively.

        In the Wholesale segment, we sell gasoline, home heating oil, diesel, kerosene and residual oil to unbranded and Mobil-branded retail gasoline stations and other resellers of transportation fuels, home heating oil retailers and wholesale distributors. In 2010, this segment accounted for approximately 93% of our total volume sold. Generally, customers use their own vehicles or contract carriers to take

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delivery of the product at bulk terminals and inland storage facilities that we own or control or with which we have throughput, exchange or other supply agreements. Please read "—Storage."

        In 2010, we sold unbranded and Mobil-branded gasoline and diesel, including Diesel One®, to approximately 1,135 wholesalers and retail gasoline station operators, vehicles, fleet and marine users and other end users throughout the Northeast.

        We have marketing arrangements with two major suppliers of unbranded gasoline as well as two distillate suppliers in several northeastern states.

        In 2010, we sold home heating oil, including Heating Oil Plus™, to 1,076 wholesale distributors and retailers. We have a fixed price sales program that we market primarily to wholesale distributors and retailers which currently uses the New York Mercantile Exchange ("NYMEX") heating oil contract as the pricing benchmark and as a vehicle to manage the commodity risk. Please read "—Commodity Risk Management." In 2010, approximately 27% of our home heating oil volume was sold using forward fixed price contracts. A forward fixed price contract requires our customer to purchase a specific volume at a specific price during a specific period. The remaining home heating oil was sold on either a posted price or a price based on various indices which, in both instances, reflect current market conditions.

        In 2010, we sold residual oil to 19 wholesale distributors. Our Wholesale residual oil sales were accomplished through forward fixed price contracts or by using market-related prices, either posted prices or indexed prices, to reflect current market conditions.

        Financial information with respect to the Wholesale segment, including information concerning revenues, gross profit, net product margin and total assets may be found under Item 7, "Management's Discussion and Analysis and Results of Operations" and in Note 17 of Notes to Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

        Our Commercial segment includes sales and deliveries of unbranded gasoline, home heating oil, diesel, kerosene, residual oil and small amounts of natural gas and renewable fuel to end user customers in the public sector and to large commercial and industrial end users. In the case of commercial and industrial end user customers, we sell our products primarily either through a competitive bidding process or through contracts of various terms. Our Commercial segment also includes sales of custom blended distillates and residual oil delivered by barges or from a terminal dock through bunkering activity as well as sales of Mobil-branded gasoline to end users. In 2010, this segment accounted for approximately 7% of our total volume sold.

        Our commercial end user customers also include Mobil-branded gasoline customers at our directly operated gasoline stations, federal and state agencies, municipalities, large industrial companies, many autonomous authorities, such as transportation authorities and water resource authorities, colleges and universities and a group of small utilities. Unlike our Wholesale segment, in our Commercial segment, we generally arrange the delivery of the product to the customer's designated location. We typically hire third-party common carriers to deliver the product. Please read "—Storage."

        In this segment, we respond to publicly-issued requests for product proposals and quotes. As of December 31, 2010, we had contracts as a result of this public bidding process with the U.S. government and the states of Massachusetts, New Hampshire and Rhode Island. We also had contracts with municipalities, autonomous authorities and institutional customers in the Northeast to meet their various fuel requirements.

        A majority of the contracts in our bid business are for a term of one to three years. We offer both fixed and indexed price and volume contracts to customers. The majority of bid activity is priced using

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an indexed price with the index typically chosen by the issuing authority in its solicitation for the bid proposal. The indexed prices are usually referenced to one of five industry publications and/or the utilization of regulated exchanges.

        Our commercial customers also include cruise ships, dry and wet bulk carriers, fishing fleets and other marine vessels. We blend distillates and residual fuel to the customers' specifications at the terminal facility or on the barge and then deliver the resulting bunker fuel directly to the ship or barge.

        Financial information with respect to the Commercial segment, including information concerning revenues, gross profit, net product margin and total assets may be found under Item 7, "Management's Discussion and Analysis and Results of Operations" and in Note 17 of Notes to Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

        Our non-petroleum product sales primarily include convenience store sales at our directly operated stores and gas station rental income.

Supply

        Our products come from some of the major energy companies in the world. Cargos are sourced from the United States, Canada, South America, Europe, Russia and occasionally from Asia. During 2010, we purchased an average of approximately 238,000 barrels per day of refined petroleum products from approximately 115 suppliers. In 2010, our top ten suppliers accounted for approximately 60% of our product purchases. We enter into supply agreements with these suppliers on a term basis or a spot basis. With respect to trade terms, our supply purchases vary depending on the particular contract from prompt payment (usually three days) to net 30 days. Please read "—Commodity Risk Management." We obtain our convenience store inventory from traditional suppliers.

Commodity Risk Management

        Since we take title to the refined petroleum products that we sell, we are exposed to commodity risk. Commodity risk is the risk of unfavorable market fluctuations in the price of commodities such as refined petroleum products. We endeavor to minimize commodity risk in connection with our daily operations. Generally, as we purchase and/or store refined petroleum products, we reduce commodity risk through hedging by selling futures contracts on regulated exchanges or using other derivatives, and then lift hedges as we sell the product for physical delivery to third parties. Products are generally purchased and sold at spot prices, fixed prices or at indexed prices. While we use these transactions to seek to maintain a position that is substantially balanced between purchased volumes versus sales volumes through regulated exchanges or derivatives, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules as well as logistical issues associated with inclement weather conditions or infrastructure disruptions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of refined petroleum products on any day. Our general policy is not to hold refined petroleum products, futures contracts or other derivative products and instruments for the sole purpose of speculating on price change. While our policies are designed to minimize market risk, some degree of exposure to unforeseen fluctuations in market conditions remains.

        Operating results are sensitive to a number of factors. Such factors include commodity location, grades of product, individual customer demand for grades or location of product, localized market price structures, availability of transportation facilities, daily delivery volumes that vary from expected quantities and timing and costs to deliver the commodity to the customer. The term "basis risk" is used to describe the inherent market price risk created when a commodity of certain grade or location is

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purchased, sold or exchanged as compared to a purchase, sale or exchange of commodity at a different time or place, including, without limitation, transportation costs and timing differentials. We attempt to reduce our exposure to basis risk by grouping our purchase and sale activities by geographical region and commodity quality in order to stay balanced within such designated region. However, basis risk cannot be entirely eliminated, and basis exposure, particularly in backward markets (when prices for future deliveries are lower than current prices) or other adverse market conditions, can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        With respect to the pricing of commodities, we enter into futures contracts to minimize or hedge the impact of market fluctuations on our purchase and forward fixed price sales of refined petroleum products. Any hedge ineffectiveness is reflected in our results of operations. We utilize the NYMEX and the Chicago Mercantile Exchange ("CME"), which are regulated exchanges for the energy products that they trade, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than make or receive physical deliveries. With respect to other energy products, which may not have a correlated exchange contract, we enter into derivative agreements with counterparties that we believe have a strong credit profile in order to hedge market fluctuations and/or lock-in margins relative to our commitments.

        We monitor processes and procedures to prevent unauthorized trading by our personnel and to maintain substantial balance between purchases and sales or future delivery obligations. We can provide no assurance, however, that these steps will detect and prevent all violations of such trading policies and procedures, particularly if deception or other intentional misconduct is involved.

Storage

        Bulk terminals and inland storage facilities play a key role in the distribution of product to our customers. In 2010, we owned, leased or maintained dedicated storage facilities at 24 refined petroleum product bulk terminals, each with the capacity of more than 50,000 barrels, including 23 located throughout the Northeast that collectively have approximately 10.2 million barrels of storage capacity. We also have throughput, exchange or other supply agreements at more than 50 bulk terminals and inland storage facilities.

        The bulk terminals and inland storage facilities from which we distribute product are supplied by ship, barge, truck, pipeline or rail. The inland storage facilities, which we use exclusively to store distillates, are supplied with product delivered by truck from bulk terminals. Our customers receive product from our network of bulk terminals and inland storage facilities via truck, barge, rail or pipeline.

        Many of our bulk terminals operate 24 hours a day and consist of multiple storage tanks and automated truck loading equipment. These automated systems monitor terminal access, volumetric allocations, credit control and carrier certification through the remote identification of customers. In addition, some of the bulk terminals at which we market are equipped with truck loading racks capable of providing automated blending and additive packages which meet our customers' specific requirements.

        Throughput arrangements allow storage of product at terminals owned by others. Our customers can load product at these terminals, and we pay the owners of these terminals fees for services rendered in connection with the receipt, storage and handling of such product. Compensation to the terminal owners may be fixed or based upon the volume of our product that is delivered and sold at the terminal.

        Exchange agreements allow our customers to take delivery of product at a terminal or facility that is not owned or leased by us. An exchange is a contractual agreement where the parties exchange product at their respective terminals or facilities. For example, we (or our customers) receive product

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that is owned by our exchange partner from such party's facility or terminal, and we deliver the same volume of our product to such party (or to such party's customers) out of one of the terminals in our terminal network. Generally, both sides of an exchange transaction pay a handling fee (similar to a throughput fee), and often one party also pays a location differential that covers any excess transportation costs incurred by the other party in supplying product to the location at which the first party receives product. Other differentials that may occur in exchanges (and result in additional payments) include product value differentials and timing differentials.

Competition

        We encounter varying degrees of competition based on product and geographic locations. Our competitors include terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying sizes, financial resources and experience. In our core Northeast market, we compete in various product lines and for all customers. In the residual oil markets, however, where product is heated when stored and cannot be delivered long distances, we face less competition because of the strategic locations of our residual oil storage facilities. We also compete with natural gas suppliers and marketers in our home heating oil and residual oil product lines. Bunkering requires facilities at ports to service vessels. In various other geographic markets, particularly the unbranded gasoline and distillates markets, we compete with integrated refiners, merchant refiners and regional marketing companies. Our Mobil-branded retail gas stations compete with unbranded and branded retail gas stations as well as supermarket and warehouse stores that sell gasoline.

Environmental

        Our business of supplying refined petroleum products involves a number of activities that are subject to extensive and stringent environmental laws. As part of our business, we own and operate various petroleum storage and distribution facilities and gas stations and must comply with environmental laws at the federal, state and local levels, which increases the cost of operating terminals and gas stations and our business generally.

        Our operations also utilize a number of petroleum storage facilities and distribution facilities and gas stations that we do not own or operate, but at which refined petroleum products are stored. We utilize these facilities through several different contractual arrangements, including leases and throughput and terminalling services agreements. If facilities with which we contract that are owned and operated by third parties fail to comply with environmental laws, they could be shut down, requiring us to incur costs to use alternative facilities.

        Environmental laws and regulations can restrict or impact our business activities in many ways, such as:

    requiring remedial action to mitigate releases of hydrocarbons, hazardous substances or wastes caused by our operations or attributable to former operators;

    requiring capital expenditures to comply with environmental control requirements; and

    enjoining the operations of facilities deemed in noncompliance with environmental laws and regulations.

        Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hydrocarbons, hazardous substances or wastes have been released or disposed of. Moreover,

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neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the release of hydrocarbons, hazardous substances or other wastes into the environment.

        The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and minimize the costs of such compliance.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders. We can provide no assurance, however, that future events, such as changes in existing laws (including changes in the interpretation of existing laws), the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

        In most instances, the environmental laws and regulations affecting our business relate to the release of hazardous substances into the water or soils and include measures to control pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under the Superfund law, these persons may be subject to joint and several liability for the costs of cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. The Superfund law also authorizes the U.S. Environmental Protection Agency ("EPA"), and in some instances third parties, to act in response to threats to the public health or the environment and seek to recover from the responsible persons the costs they incur. It is possible for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate, store or otherwise handle materials and wastes that fall within the Superfund law's definition of a hazardous substance and, as a result, we may be jointly and severally liable under the Superfund law for all or part of the costs required to clean up sites at which those hazardous substances have been released into the environment.

        We currently own, lease or utilize storage or distribution facilities and gas stations where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on, under or from the properties owned or leased by us or on or under other locations where we have contractual arrangements or where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to the Superfund law or other federal and 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, clean up contaminated property, including groundwater contaminated by prior owners or operators or make capital improvements to prevent future contamination.

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        Our operations generate a variety of wastes, including some hazardous wastes that are subject to the federal Resource Conservation and Recovery Act, as amended ("RCRA") and comparable state laws. By way of summary, these regulations impose detailed requirements for the handling, storage, treatment and disposal of hazardous waste. Our operations also generate solid wastes which are regulated under state law or the less stringent solid waste requirements of the federal Solid Waste Disposal Act. We believe that we are in substantial compliance with the existing requirements of RCRA, the Solid Waste Disposal Act, and similar state and local laws, and the cost involved in complying with these requirements is not material.

        We incur ongoing costs for monitoring groundwater and/or remediation of contamination at several facilities that we operate. Assuming that we will be able to continue to use common remedial and monitoring methods or associated engineering or institutional controls to demonstrate compliance with applicable regulatory requirements, as we have in the past and regulations currently allow, we believe that these costs will not have a material impact on our financial condition, results of operations or cash available for distribution to our unitholders.

        Above ground tanks that contain petroleum and other hazardous substances are subject to comprehensive regulation under environmental laws. Generally, these laws impose liability for releases and require secondary containment systems for tanks or that the operators take alternative precautions to ensure that no contamination results from tank leaks or spills. We believe we are in substantial compliance with environmental laws and regulations applicable to above ground storage tanks.

        The Oil Pollution Act of 1990 ("OPA") addresses three principal areas of oil pollution—prevention, containment and cleanup. In order to handle, store or transport oil, we are required to file oil spill response plans with either the United States Coast Guard (for marine facilities) or the EPA. States in which we operate have enacted laws similar to OPA. Under OPA and comparable state laws, responsible parties for a regulated facility from which oil is discharged may be subject to strict, joint and several liability for removal costs and certain other consequences of an oil spill such as natural resource damages, where the spill is into navigable waters or along shorelines. We believe we are in substantial compliance with regulations pursuant to OPA and similar state laws.

        Under the authority of the federal Clean Water Act, the EPA imposes specific requirements for Spill Prevention, Control and Countermeasure plans that are designed to prevent, and minimize the impacts of, releases of oil and oil products from above ground storage tanks. We believe we are in substantial compliance with these requirements.

    Underground Storage Tanks

        We are required to make financial expenditures to comply with regulations governing underground storage tanks which store gasoline or other regulated substances adopted by federal, state and local regulatory agencies. Pursuant to RCRA, the EPA has established a comprehensive regulatory program for the detection, prevention, investigation and cleanup of leaking underground storage tanks. State or local agencies are often delegated the responsibility for implementing the federal program or developing and implementing equivalent or stricter state or local regulations. We have a comprehensive program in place for performing routine tank testing and other compliance activities which are intended to promptly detect and investigate any potential releases. In addition, the federal Clean Air Act and similar state laws impose requirements on emissions to the air from motor fueling activities in certain areas of the country, including those that do not meet state or national ambient air quality standards. These laws may require the installation of vapor recovery systems to control emissions of volatile organic compounds to the air during the motor fueling process. We believe we are in substantial compliance with applicable environmental requirements, including those applicable to our

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underground storage tanks. Compliance with existing and future environmental laws regulating underground storage tank systems of the kind we use may require significant capital expenditures in the future. These expenditures may include upgrades, modifications, and the replacement of underground storage tanks and related piping to comply with current and future regulatory requirements designed to ensure the detection, prevention, investigation and remediation of leaks and spills.

        The federal Clean Water Act imposes restrictions regarding the discharge of pollutants, including oil and refined petroleum products, into navigable waters. This law and comparable state laws require permits for discharging pollutants into state and federal waters and impose substantial liabilities and remedial obligations for noncompliance. EPA regulations also require us to obtain permits to discharge certain storm water runoff. Storm water discharge permits also may be required by certain states in which we operate. We believe that we hold the required permits and operate in material compliance with those permits. While we have experienced permit discharge exceedences at some of our terminals, we do not expect any noncompliance with existing permits and foreseeable new permit requirements to have a material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.

        Under the federal Clean Air Act and comparable state and local laws, permits are typically required to emit regulated air pollutants into the atmosphere. We believe that we currently hold or have applied for all necessary air permits and that we are in substantial compliance with applicable air laws and regulations. Although we can give no assurances, we are aware of no changes to air quality regulations that will have a material adverse effect on our financial condition, results of operations or cash available for distribution to our unitholders.

        Various federal, state and local agencies have the authority to prescribe product quality specifications for the refined petroleum products that we sell, largely in an effort to reduce air pollution. Failure to comply with these regulations can result in substantial penalties. Although we can give no assurances, we believe we are currently in substantial compliance with these regulations.

        Changes in product quality specifications could require us to incur additional handling costs or reduce our throughput volume. For instance, different product specifications for different markets could require the construction of additional storage. Also, states in which we operate have considered limiting the sulfur content of home heating oil. If such regulations are enacted, this could restrict the supply of available heating oil, which could increase our costs to purchase such oil or limit our ability to sell heating oil.

        Efforts at the federal and state level are currently underway to reduce the levels of greenhouse gas ("GHG") emissions from various sources in the United States. At the federal level, legislation was introduced in Congress in 2007-2010 to reduce GHG emissions in the United States. Such or similar federal legislation may impose a carbon emissions tax or establish a cap-and-trade program or regulation by the EPA. Even in the absence of new federal legislation, GHG emissions have begun to be regulated by the EPA pursuant to the Clean Air Act. In December of 2009, the EPA issued a final rule declaring that six GHGs, including carbon dioxide and methane, "endanger both the public health and the public welfare of current and future generations." The issuance of this "endangerment finding" allowed the EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. In May 2010, the EPA issued a final "tailoring rule" that would regulate GHG emissions from large stationary sources such as power plants or industrial facilities. In addition, in April 2010, the EPA set a new emissions standard for motor vehicles to reduce GHG emissions. In December 2010, the EPA issued its plan to update pollution standards for fossil fuel power plants and petroleum refineries.

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Under that agreement, the EPA intends to propose standards for power plants in July 2011 and for refineries in December 2011 and will issue final standards in May 2012 and November 2012, respectively. Numerous states, including many where we have operations, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. A regional cap and trade program, referred to as the Regional Greenhouse Gas Initiative, began January 1, 2009, and is designed to stabilize and reduce GHG emissions from fossil fuel-fired power plants in many northeastern and mid-atlantic states. New federal or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which we conduct business and that apply to our operations could adversely affect the demand for our products.

        On December 30, 2010 the EPA issued final rules under Subpart W of the Mandatory Greenhouse Gas Reporting Rule ("MRR"), which applies to petroleum and natural gas systems. Under Subpart W, any facility in a covered sector emitting more than 25,000 metric tones of carbon dioxide equivalent per year must monitor and report their GHG emissions to the EPA. Monitoring obligations under Subpart W became effective on January 1, 2011. Currently, Subpart W only covers onshore and offshore petroleum and natural gas production; onshore natural gas processing; underground natural gas storage; liquefied natural gas storage, import and export; and natural gas distribution. Because we are not engaged in production activities or natural gas distribution, we do not believe that we are currently subject to the requirements of MRR Subpart W. In addition, under Subpart MM, importers of petroleum products, including distillates, must report the GHG emissions that would result from the complete combustion of all imported products if such combustion would result in the emission of at least 25,000 metric tons of carbon dioxide per year. At this time, we believe that we may be subject to Subpart MM because we import a volume of petroleum products that may produce sufficient emissions to trigger a reporting obligation. We do not believe that compliance with the MRR will substantially impact our operations.

    Convenience Store Regulations

        Our convenience store operations are subject to extensive governmental laws and regulations that include, but are not limited to, legal restrictions on the sale of alcohol, tobacco and lottery products, food safety and health requirements and public accessibility, as well as sanitation, safety and fire standards. State and local regulatory agencies have the authority to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses. Our operations are also subject to federal and state laws governing matters such as wage rates, overtime, working conditions and citizenship requirements. At the federal level, there are proposals under consideration from time to time to increase minimum wage rates and to introduce a system of mandated health insurance, each of which could adversely affect our results of operations. In June 2009, Congress gave the Food and Drug Administration ("FDA"), broad authority to regulate tobacco products through passage of the Family Smoking Prevention and Tobacco Control Act ("FSPTCA"). Under the FSPTCA, the FDA has passed regulations that, among other things, prohibit the sale of cigarettes or smokeless tobacco to anyone under the age of 18 years (state laws are permitted to set a higher minimum age); prohibit the sale of single cigarettes or packs with less than 20 cigarettes; and prohibit the sale or distribution of non-tobacco items such as hats and t-shirts with tobacco brands, names or logos. Governmental actions and regulations, such as these, could materially impact our retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on our results of operations.

    Ethanol Market

        The market for ethanol is dependent on several economic incentives to use ethanol, including federal tax incentives, ethanol use mandates and oxygenate blending requirements. For instance, the

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Renewable Fuels Standard ("RFS") requires that a certain amount of renewable fuels be utilized in the United States each year. Additionally, the EPA imposes oxygenate blending requirements for reformulated gasoline. The market for ethanol is also affected by the Volumetric Ethanol Excise Tax Credit ("blender's credit"), which provides a volumetric tax credit of 4.5 cents per gallon of gasoline that contains at least 10% ethanol. The blender's credit was recently renewed until December 31, 2011. A reduction or waiver of the RFS mandate or the oxygenate blending requirements or the failure to extend the blender's credit could adversely affect the availability and pricing of ethanol, which could result in reduced discretionary blending of ethanol. Discretionary blending is when gasoline blenders use ethanol to reduce the cost of blended gasoline.

        Recently, the EPA allowed the use of E15, gasoline which is blended at a rate of 15% ethanol and 85% gasoline, in vehicles manufactured in the model year 2007 and later as well as for cars and light duty trucks manufactured in the model years between 2001 and 2006. According to EPA estimates, flex-fuel vehicles make up only 7.3 million of the 240 million vehicles on the nation's roads and there are only about 2,000 E85 pumps in the U.S. The USDA recently announced that it will provide financial assistance to help implement more "blender pumps" in the U.S. in order to increase demand for ethanol and to help offset the cost of introducing mid-level ethanol blends into the U.S. retail gasoline market. However, blender pumps cost approximately $25,000 each, so it may take time before they become widely available in the retail gasoline market.

        We maintain insurance which may cover, in whole or in part, certain costs relating to the clean up of releases of refined petroleum products. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. These policies may not cover all environmental risks and costs and may not provide sufficient coverage in the event an environmental claim is made against us.

Security Regulation

        Since the September 11, 2001 terrorist attacks on the United States, the U.S. government has issued warnings that energy infrastructure assets may be future targets of terrorist organizations. These developments have subjected our operations to increased risks. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Where required by federal or local laws, we have prepared security plans for the storage and distribution facilities we operate. Terrorist attacks aimed at our facilities and any global and domestic economic repercussions from terrorist activities could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. For instance, terrorist activity could lead to increased volatility in prices for home heating oil, gasoline and other products we sell.

        Insurance carriers are currently required to offer coverage for terrorist activities as a result of the federal Terrorism Risk Insurance Act of 2002 ("TRIA"). We purchased this coverage with respect to our property and casualty insurance programs, which resulted in additional insurance premiums. Pursuant to the Terrorism Risk Insurance Program Reauthorization Act of 2007, TRIA has been extended through December 31, 2014. Although we cannot determine the future availability and cost of insurance coverage for terrorist acts, we do not expect the availability and cost of such insurance to have a material adverse effect on our financial condition, results of operations or cash available for distribution to our unitholders.

Employee Safety

        We are subject to the requirements of the Occupational Safety and Health Act ("OSHA") and comparable state statutes that regulate the protection of the health and safety of workers. In addition,

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OSHA's hazard communication standards require that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with the applicable OSHA requirements.

        We operate a limited number of trucks for the transportation of refined petroleum products, as most of the trucks that distribute products we sell are owned and operated by third parties. We are subject to regulations promulgated under the Federal Motor Carrier Safety Act for those trucks that we do operate. These regulations cover the transportation of hazardous materials and are administered by the U.S. Department of Transportation. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations.

Title to Properties, Permits and Licenses

        We believe we have all of the assets needed, including leases, permits and licenses, to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on our financial position, results of operations or cash available for distribution to our unitholders.

        We believe we have satisfactory title to all of our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with the use of these properties in the operation of our business.

        The name GLOBAL, our logos and the name Global Petroleum Corp. are trademarks of Global Companies LLC. In addition, we have trademarks for our premium fuels and additives, Diesel One®, Heating Oil Plus™ and SubZero®.

Facilities

        We lease office space for our principal executive office in Waltham, Massachusetts. The lease expires on December 31, 2015.

Employees

        To carry out our operations, our general partner and certain of our operating subsidiaries employed 286 full-time employees as of December 31, 2010. We believe we have good relations with our employees.

        Certain of the employees assigned to our terminal in Chelsea, Massachusetts are employed under collective bargaining agreements that expire in 2011 and which we expect will be renewed in the ordinary course. Certain of Global Petroleum Corp.'s employees at the Revere, Massachusetts facility are also employed under a collective bargaining agreement that expires in 2011 and which we expect will be renewed in the ordinary course. Certain of the employees assigned to our terminals in Albany, Newburgh, Glenwood Landing and Inwood, New York are employed under collective bargaining agreements that expire in May 2013 (with respect to Albany and Newburgh) and April 2011 (with respect to Glenwood Landing and Inwood and which we expect will be renewed in the ordinary course). Certain of the employees assigned to our terminal in Oyster Bay (Commander), New York are employed under a collective bargaining agreement that expired in May 2010. We have negotiated an agreement, in principle, with the Commander employees and expect that a successor collective bargaining agreement will be executed in the first quarter of 2011. One other employee at Commander is employed under a collective bargaining agreement that expires in 2011 and which we expect will be renewed in the ordinary course.

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        We have two shared services agreements, one with Global Petroleum Corp. and another with Alliance Energy LLC. The services provided among these entities by any employees shared pursuant to these agreements does not limit the ability of such employees to provide all services necessary to properly run our business. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Shared Services Agreements."

Item 1A.    Risk Factors.

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution or maintain distributions at current levels following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

        We may not have sufficient available cash each quarter to pay the minimum quarterly distribution or maintain distributions at current levels. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

    competition from other companies that sell refined petroleum products and natural gas and renewable fuels in the Northeast;

    demand for refined petroleum products in the markets we serve;

    absolute price levels, as well as the volatility of prices, of refined petroleum products in both the spot and futures markets;

    seasonal variation in temperatures, which affects demand for home heating oil and residual oil to the extent that it is used for space heating;

    the level of our operating costs, including payments to our general partner; and

    prevailing economic conditions.

        In addition, the actual amount of cash we have available for distribution will depend on other factors such as:

    the level of capital expenditures we make;

    the restrictions contained in our credit agreement, including borrowing base limitations and advance rates;

    our debt service requirements;

    the cost of acquisitions;

    fluctuations in our working capital needs;

    our ability to borrow under our credit agreement to make distributions to our unitholders; and

    the amount of cash reserves established by our general partner, if any.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

        The amount of cash we have available for distribution depends primarily on our cash flow, including working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

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Our financial results are seasonal and generally lower in the second and third quarters of the calendar year, which may result in our need to borrow money in order to make distributions to our unitholders during these quarters.

        Demand for some refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally higher during November through March than during April through October. We obtain a significant portion of our sales of home heating oil and residual oil for space heating purposes during these winter months. Therefore, our results of operations for the first and fourth calendar quarters are generally better than for the second and third quarters. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to pay the minimum quarterly distribution to our unitholders. Any restrictions on our ability to borrow money could restrict our ability to make quarterly distributions to our unitholders.

A significant decrease in demand for refined petroleum products in the areas we serve would reduce our ability to make distributions to our unitholders.

        A significant decrease in demand for refined petroleum products in the areas that we serve could significantly reduce our revenues and, therefore, reduce our ability to make or increase distributions to our unitholders. Factors that could lead to a decrease in market demand for refined petroleum products include:

    lower demand by consumers for refined petroleum products, including gasoline, home heating oil and residual oil, as a result of recession or other adverse economic conditions or due to high prices caused by an increase in the market price of refined petroleum products or higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined petroleum products;

    a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy of vehicles, whether as a result of technological advances by manufacturers, governmental or regulatory actions or otherwise; and

    conversion from consumption of home heating oil or residual oil to natural gas.

        Certain of our operating costs and expenses are fixed and do not vary with the volumes we store and distribute. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes stored, distributed and sold. As a result, we may experience declines in our margin if our volumes decrease.

Our financial condition and results of operations are influenced by increases and/or decreases in the prices of refined petroleum products which may adversely impact our margins, our customer's financial condition, contract performance, trade credit, as well as the amount of borrowing available for working capital under our credit agreement, which credit agreement has borrowing base limitations and advance rates.

        Results from our purchasing, storing, terminalling and selling operations are influenced by prices for refined petroleum products, pricing volatility and the market for such products. When prices for refined petroleum products rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs to our customers, resulting in lower margins for us which could adversely affect our results of operations. Lastly, higher prices for refined petroleum products may (1) diminish our access to trade credit support and/or cause it to become more expensive and (2) decrease the amount of borrowings available for working capital under our credit agreement as a result of total available commitments, borrowing base limitations and advance rates thereunder.

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        In addition, when prices for refined petroleum products decline, our exposure to risk of loss in the event of nonperformance by our customers on forward contracts may be increased as they and/or their customers may breach their contracts and purchase refined petroleum products at the then lower spot and/or retail market price. Furthermore, lower prices for refined petroleum products may diminish the amount of borrowings available for working capital under our working capital revolving credit facility as a result of borrowing base limitations.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

        We have a significant amount of debt. As of December 31, 2010, our total debt was approximately $786.7 million. We have the ability to incur additional debt, including the capacity to borrow up to $1.15 billion under our credit facilities, subject to limitations in our credit agreement. Our level of indebtedness could have important consequences to us, including the following:

    our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

    covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

    we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;

    our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally; and

    our debt level may limit our flexibility in responding to changing business and economic conditions.

        Our ability to service our indebtedness depends upon, among other things, our financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions, such as reducing distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

We may not be able to obtain funding on acceptable terms or obtain additional requested funding in excess of total commitments under our credit agreement, which could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        Over the recent past, global financial markets and economic conditions were disrupted and volatile. The debt and equity capital markets were exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the economic conditions, had made and, along with any other potential future economic or market uncertainties, could make it difficult to obtain funding.

        As a result, the cost of raising money in the debt and equity capital markets could increase while the availability of funds from those markets could diminish. The cost of obtaining money from the

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credit markets could increase as many lenders and institutional investors increase interest rates, enact tighter lending standards and reduce and, in some cases, cease to provide funding to borrowers.

        In addition, we may be unable to obtain adequate funding under our credit agreement because (i) one or more of our lenders may be unable to meet its funding obligations or (ii) our borrowing base under our credit agreement, as redetermined from time to time, may decrease as a result of price fluctuations, counterparty risk, advance rates and borrowing base limitations and customer nonpayment or nonperformance.

        Due to these factors, we cannot be certain that funding will be available if needed and to the extent required or requested on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to maintain our core business as currently conducted, 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 financial condition, results of operations and cash available for distribution to our unitholders.

Our credit agreement contains operating and financial restrictions that may restrict our business and financing activities.

        The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, our credit agreement restricts our ability to:

    grant liens;

    make certain loans or investments;

    incur additional indebtedness or guarantee other indebtedness;

    make any material change to the nature of our business or undergo a fundamental change;

    make any material dispositions;

    acquire another company;

    enter into a merger, consolidation, sale leaseback transaction or purchase of assets;

    make distributions if any potential default or event of default occurs;

    modify borrowing base components and advance rates; or

    make capital expenditures in excess of specified levels.

        Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit agreement are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders could seek to foreclose on such assets.

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Restrictions in our credit agreement limit our ability to pay distributions upon the occurrence of certain events.

        Our credit agreement limits our ability to pay distributions upon the occurrence of the following events, among others:

    failure to pay any principal when due or any interest, fees or other amounts when due;

    failure of any representation or warranty to be true and correct in any material respect;

    failure to perform or otherwise comply with the covenants in the credit agreement or in other loan documents to which we are a borrower;

    any default in the performance of any obligation or condition beyond the applicable grace period relating to any other indebtedness of more than $2.0 million if the effect of the default is to permit or cause the acceleration of the indebtedness;

    a judgment default for monetary judgments exceeding $2.0 million or a default under any non-monetary judgment if such default could have a material adverse effect on us;

    a change in management or ownership control; and

    a violation of the Employee Retirement Income Security Act, or ERISA, or a bankruptcy or insolvency event involving us, our general partner or any of our subsidiaries.

        Any subsequent refinancing of our current debt or any new debt could have similar restrictions. For more information regarding our credit agreement, please read Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement" and Note 8 of Notes to Consolidated Financial Statements.

We can borrow money under our credit agreement to pay distributions, which would reduce the amount of credit available to operate our business.

        Our partnership agreement allows us to borrow under our credit agreement to pay distributions. Accordingly, we can make distributions on all our units even though cash generated by our operations may not be sufficient to pay such distributions. For more information, please read Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement" and Note 8 of Notes to Consolidated Financial Statements.

Warmer weather conditions could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        Weather conditions have an impact on the demand for both home heating oil and residual oil. Because we supply distributors whose customers depend on home heating oil and residual oil for space heating purposes during the winter, warmer-than-normal temperatures during the first and fourth calendar quarters in one or more regions in which we operate can decrease the total volume we sell and the gross profit realized on those sales and, consequently, our financial condition, results of operations and cash available for distribution to our unitholders.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity prices, interest rate and other risks associated with our business.

        The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was signed into law by the President on

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July 21, 2010 and requires the Commodities Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the Dodd-Frank Act. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

        The new legislation and any new regulations could significantly increase the cost of some derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of some derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Our risk management policies cannot eliminate all commodity risk, basis risk, or the impact of adverse market conditions which can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders. In addition, any noncompliance with our risk management policies could result in significant financial losses.

        While our hedging policies are designed to minimize commodity risk, some degree of exposure to unforeseen fluctuations in market conditions remains. For example, we change our hedged position daily in response to movements in our inventory. If we overestimate or underestimate our sales from inventory, we may be unhedged for the amount of the overestimate or underestimate. Also, significant increases in the costs of refined petroleum products can materially increase our costs to carry inventory. We use our credit facility as our primary source of financing to carry inventory and may be limited on the amounts we can borrow to carry inventory.

        Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. For example, we use the NYMEX to hedge our commodity risk with respect to pricing of energy products traded on the NYMEX. Physical deliveries under NYMEX contracts are made in New York Harbor. To the extent we take deliveries in other ports, such as Boston Harbor, we may have basis risk. In a backward market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as basis declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backward or other adverse market conditions, can adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        We monitor processes and procedures to prevent unauthorized trading and to maintain substantial balance between purchases and sales or future delivery obligations. We can provide no assurance, however, that these steps will detect and/or prevent all violations of such risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

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We are exposed to trade credit risk and risk associated with our trade credit support in the ordinary course of our business activities.

        We are exposed to risks of loss in the event of nonperformance by our customers and by counterparties of our forward and futures contracts, options and swap agreements and by our suppliers. Some of our customers, counterparties and suppliers may be highly leveraged and subject to their own operating and regulatory risks. The tightening of credit in the financial markets may make it more difficult for customers and counterparties to obtain financing and, depending on the degree to which it occurs, there may be a material increase in the nonpayment and nonperformance of our customers and counterparties. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our customers and/or counterparties and the nonperformance by our suppliers could reduce our ability to make distributions to our unitholders.

        Additionally, our access to trade credit support could diminish and/or become more expensive. Our ability to continue to receive sufficient trade credit on commercially acceptable terms could be adversely affected by fluctuations in refined petroleum product prices or disruptions in the credit markets or for any other reason.

We are exposed to performance risk in our supply chain.

        We rely upon our suppliers to timely produce the volumes and types of refined petroleum products for which they contract with us. In the event one or more of our suppliers does not perform in accordance with its contractual obligations, we may be required to purchase product on the open market to satisfy forward contracts we have entered into with our customers in reliance upon such supply arrangements. We purchase refined petroleum products from a variety of suppliers under term contracts and on the spot market. In times of extreme market demand, we may be unable to satisfy our supply requirements. Furthermore, a portion of our supply comes from other countries, which could be disrupted by political events. In the event such supply becomes scarce, whether as a result of political events, natural disaster, logistical issues associated with delivery schedules or otherwise, we may not be able to satisfy our supply requirements. If any of these events were to occur, we may be required to pay more for product that we purchase on the open market, which could result in financial losses and adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

Some of our competitors have capital resources many times greater than ours and control greater supplies of refined petroleum products.

        Our competitors include terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying sizes, financial resources and experience. Some of our competitors have capital resources many times greater than ours and control greater supplies of refined petroleum products. If we are unable to compete effectively, we may lose existing customers or fail to acquire new customers, which could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. For example, if a competitor attempts to increase market share by reducing prices, our operating results and cash available for distribution to our unitholders could be adversely affected. We may not be able to compete successfully with these companies.

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Some of our residual oil volumes are subject to customers switching or converting to natural gas which could result in loss of customers, which in turn could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        Our residual oil business competes for customers with suppliers of natural gas. Those end users who are dual-fuel users have the ability to switch from residual oil to natural gas. Other end users may elect to convert to natural gas. During a period of increasing residual oil prices relative to the prices of natural gas, dual-fuel using customers may switch and other end users may convert to natural gas. Such switching and conversions could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. We could face additional competition from alternative energy sources, such as natural gas, as a result of government-mandated controls or regulation promoting the use of cleaner fuels. Residual oil consumption has steadily declined over the last three decades.

Some of our heating oil volumes are subject to residential conversion to natural gas which could result in less demand for home heating oil and, in turn, could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        Our heating oil business competes for customers with suppliers of natural gas. During a period of increasing home heating oil prices relative to prices of natural gas, home heating oil users may convert to natural gas. Such conversions could reduce our sales of home heating oil and have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Erosion of the Mobil brand could have an adverse impact on our sales of Mobil-branded gasoline.

        We believe that the success of our acquisition of retail gas stations and supply rights from ExxonMobil may be dependent, in part, upon the continuing favorable reputation of the Mobil brand. Erosion of the value of the Mobil brand could have a negative impact on our gasoline sales, which in turn may cause our recent acquisition to be less profitable.

New technologies and alternative fuel sources could reduce demand for our gasoline products.

        Technological advances and alternative fuel sources, such as electric, hybrid or battery powered motor vehicles, may adversely affect the demand for gasoline. We could face additional competition from alternative energy sources as a result of future government-mandated controls or regulations which promote the use of alternative fuel sources. A reduction in demand for our gasoline products could have an adverse effect on our financial condition, results of operations and cash available for distributions to our unitholders.

The ethanol industry is highly dependent upon government usage mandates and tax credits. Changes to these mandates and/or tax credits could adversely affect the availability and pricing of ethanol and negatively impact our gasoline sales.

        Our ethanol purchasing, transporting, blending and sales activities subject us to various risks including operating risks, risks of supply disruption, commodity price fluctuations and changes in government mandates and regulations. The domestic market for ethanol is tied to federal mandates for blending ethanol with gasoline. Future demand will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the blender's credit and the EPA's regulations on the RFS program. Any significant increase in production capacity beyond the RFS level may have an adverse impact on ethanol prices, and the RFS mandate with respect to ethanol derived from grain could be reduced or waived entirely. The blender's credit is currently authorized through December 31, 2011. A reduction or waiver of the RFS mandate or the

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failure to extend the blender's credit could adversely affect the availability and pricing of ethanol and our gasoline and ethanol sales.

We may not be able to obtain state fund or insurance reimbursement of our environmental remediation costs.

        Where releases of refined petroleum products have occurred, federal and state laws and regulations require that contamination caused by such releases be assessed and remediated to meet applicable standards. Our obligation to remediate this type of contamination varies, depending upon applicable laws and regulations and the extent of, and the facts relating to, the release. A portion of the remediation costs may be recoverable from the reimbursement fund of the applicable state (with respect to gas stations) and/or from third party insurance after any deductible has been met, but there are no assurances that such reimbursement funds or insurance proceeds will be available to us.

Future consumer or other litigation could adversely affect our financial condition and results of operations.

        Our retail gasoline and convenience store operations are characterized by a high volume of customer traffic and by transactions involving an array of products. These operations carry a higher exposure to consumer litigation risk when compared to the operations of companies operating in many other industries. Consequently, we may become a party to individual personal injury, or products liability and other legal actions in the ordinary course of our retail gasoline and convenience store business. While these actions are generally routine in nature, incidental to the operation of business and immaterial in scope, if our assessment of any action or actions should prove inaccurate, our financial condition and results of operations could be adversely impacted. Additionally, we are occasionally exposed to industry-wide or class action claims arising from the products we carry or industry-specific business practices. Our defense costs and any resulting damage awards or settlement amounts may not be fully covered by our insurance policies. An unfavorable outcome or settlement of one or more of these lawsuits could have a material adverse effect on our financial condition, results of operations and cash available for distributions.

We depend upon a small number of suppliers for a substantial portion of our convenience store merchandise inventory. A disruption in supply or an unexpected change in our relationships with our principal merchandise suppliers could have an adverse effect on our convenience store results of operations.

        We purchase convenience store merchandise inventory from a small number of suppliers for our directly operated convenience stores. A change of merchandise suppliers, a disruption in supply or a significant change in our relationships with our principal merchandise suppliers could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

We face intense competition in our purchasing, terminalling and storage activities. Competition from other providers of refined petroleum products and natural gas that are able to supply our customers with those products and services at a lower price could reduce our ability to make distributions to our unitholders.

        We are subject to competition from other refined petroleum product distributors and suppliers of natural gas and renewable fuels that may be able to supply our customers with the same or comparable products and terminalling and storage services on a more competitive basis. We compete with terminal companies, major integrated oil companies and their marketing affiliates and independent marketers of varying sizes, financial resources and experience. Some of these competitors are substantially larger than us, have greater financial resources and control substantially greater storage capacity than we do. Our ability to compete could be harmed by factors including, but not limited to, price competition and the availability of alternative and less expensive fuels.

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Energy efficiency, new technology and alternative fuels could reduce demand for our products and adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        Increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, have adversely affected the demand for home heating oil and residual oil. Future conservation measures and technological advances in heating, conservation, energy generation or other devices might reduce demand and adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

A principal focus of our business strategy is to grow and expand our business through acquisitions. If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

        A principal focus of our business strategy is to grow and expand our business through acquisitions. Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated per unit from operations. If we are unable to make these accretive acquisitions, either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

        Any acquisition involves potential risks, including, among other things:

    mistaken assumptions about volumes, revenues and costs, including synergies;

    an inability to integrate successfully the businesses we acquire;

    an inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets;

    the assumption of unknown liabilities;

    limitations on rights to indemnity from the seller;

    mistaken assumptions about the overall costs of equity or debt;

    the diversion of management's and employees' attention from other business concerns;

    unforeseen difficulties operating in new product areas or new geographic areas; and

    customer or key employee losses at the acquired businesses.

Our acquisition strategy involves risks that could reduce our ability to make distributions to our unitholders.

        Even if we consummate acquisitions that we believe will be accretive, they may in fact result in no increase or even a decrease in cash available for distribution to our unitholders. Any acquisition involves potential risks, including:

    performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;

    a significant increase in our indebtedness and working capital requirements;

    the inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business;

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    the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition, for which we are not indemnified or for which the indemnity is inadequate;

    customer or key employee loss from the acquired businesses; and

    diversion of our management's attention from other business concerns.

        If any acquisitions we ultimately consummate do not generate expected increases in cash available for distribution to our unitholders, our ability to make such distributions will be reduced.

We may not be able to renew our leases or our agreements for dedicated storage when they expire.

        The bulk terminals we own or lease or at which we maintain dedicated storage facilities play a key role in moving product to our customers. We lease the entirety of two bulk terminals that we operate exclusively for our business and maintain dedicated storage facilities at another eight bulk terminals. The agreements governing these arrangements are subject to expiration at various dates through 2019. These arrangements may not be renewed when they expire or, if renewed, may not be renewed at rates and on terms at least as favorable. If these agreements are not renewed or we are unable to renew these agreements at rates and on terms at least as favorable, it could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

A material amount of our terminalling capacity is controlled by one of our affiliates. Loss of that capacity could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        We currently have an exclusive throughput arrangement for a terminal located in Revere, Massachusetts with one of our affiliates, Global Petroleum Corp. (which entity is owned by Alfred A. Slifka and Richard Slifka). As of December 31, 2010, this facility accounted for approximately 21% of our storage capacity. We store distillates and gasoline at this facility. The throughput agreement for this facility expires in 2014. After expiration of the agreement, we can provide no assurance that Global Petroleum Corp. will continue to grant us exclusive use of the terminal or that the terms of a renegotiated agreement will be as favorable to us as the agreement it replaces. If we are unable to renew the agreement or unable to renew on terms at least as favorable, it could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

Some of our sales are generated under contracts that must be renegotiated or replaced periodically. If we are unable to successfully renegotiate or replace these contracts, our financial condition, results of operations and cash available for distribution to our unitholders could be adversely affected.

        Most of our arrangements with our customers are for a single season or on a spot basis. As these contracts expire, they must be renegotiated or replaced. We may be unable to renegotiate or replace these contracts when they expire, and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. Whether these contracts are successfully renegotiated or replaced is often subject to factors beyond our control. Such factors include fluctuations in refined petroleum product and natural gas prices, counterparty ability to pay for or accept the contracted volumes and a competitive marketplace for the services offered by us. If we cannot successfully renegotiate or replace our contracts or renegotiate or replace them on less favorable terms, sales from these arrangements could decline, and our financial condition, results of operations and cash available for distribution to our unitholders could be adversely affected.

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Due to our lack of asset and geographic diversification, adverse developments in the terminals we use or in our operating areas would reduce our ability to make distributions to our unitholders.

        We rely primarily on sales generated from products distributed from the terminals we own or control or to which we have access. Furthermore, the majority of our assets and operations are located in the Northeast. Due to our lack of diversification in asset type and location, an adverse development in these businesses or areas, including adverse developments due to catastrophic events or weather and decreases in demand for refined petroleum products, could have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

        We are not fully insured against all risks incident to our business. Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures, disruptions in supply infrastructure or logistics and other events beyond our control. If any of these events were to occur, we could incur substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment or suspension of our related operations.

        Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our financial condition, results of operations and cash available for distribution to unitholders.

New, stricter environmental laws and regulations could significantly increase our costs, which could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        Our operations are subject to federal, state and local laws and regulations regulating product quality specifications and other environmental matters. The trend in environmental regulation is towards more restrictions and limitations on activities that may affect the environment. Our financial condition, results of operations and cash available for distribution to our unitholders may be adversely affected by increased costs and liabilities resulting from such stricter laws and regulations. We try to anticipate future regulatory requirements that might be imposed and to plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. However, there can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith.

Our terminalling operations are subject to federal, state and local laws and regulations relating to environmental protection and operational safety that could require us to incur substantial costs.

        The risk of substantial environmental costs and liabilities is inherent in terminal operations, and we may incur substantial environmental costs and liabilities. Our terminalling operations involving the receipt, storage and redelivery of refined petroleum products are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, operational safety and related matters. Compliance with these laws and regulations increases our overall cost of business, including our capital costs to maintain and upgrade equipment and facilities. We utilize a number of terminals that are owned and operated by third parties who are also subject to these stringent federal, state and local environmental laws in

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their operations. Their compliance with these requirements could increase the cost of doing business with these facilities.

        In addition, our operations could be adversely affected if shippers of refined petroleum products incur additional costs or liabilities associated with environmental regulations. These shippers could increase their charges to us or discontinue service altogether.

        Various governmental authorities, including the EPA, have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including fines, injunctions or both. Joint and several liability may be incurred, without regard to fault or the legality of the original conduct, under federal and state environmental laws for the remediation of contaminated areas at our facilities and those where we do business. Private parties, including the owners of properties located near our terminal facilities and those with whom we do business, also may have the right to pursue legal actions against us to enforce compliance with environmental laws, as well as seek damages for personal injury or property damage. We may also be held liable for damages to natural resources.

        The possibility exists that new, stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. We may incur increased costs because of stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. New environmental regulations, such as those related to the emissions of greenhouse gases, might adversely affect our products and activities, including the storage of refined petroleum products, as well as waste management and our control of air emissions. Enactment of laws and passage of regulations regarding GHG emissions, or other actions to limit carbon dioxide emissions may reduce demand for fossil fuels and impact our business. Federal and state agencies also could impose additional safety regulations to which we would be subject. Because the laws and regulations applicable to our operations are subject to change, we cannot provide any assurance that compliance with future laws and regulations will not have a material effect on our results of operations.

Increased regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for refined petroleum products as a fuel source, which could reduce demand for our products, decrease our revenues and reduce our profitability.

        Combustion of fossil fuels, such as the refined petroleum products we sell, results in the emission of carbon dioxide into the atmosphere. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes, and the EPA has begun to regulate GHG emissions pursuant to the Clean Air Act. In addition, it is possible federal legislation could be adopted in the future to restrict GHG, as President Obama has expressed support for a mandatory cap and trade program to restrict or regulate emissions of greenhouse gases, and Congress has recently considered various proposals to reduce GHG emissions. Many states and regions have adopted GHG initiatives. Please read "Item 1. Business—Environmental—Air Emissions."

        There are many regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program and regulation by the EPA. The 2010 congressional mid-term elections, especially the loss of the Democratic majority in the House of Representatives, will probably change the EPA's approach in 2011 and beyond. Future international, federal and state initiatives to control carbon dioxide emissions could result in increased

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costs associated with refined petroleum products consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs could result in reduced demand for refined petroleum products and some customers switching to alternative sources of fuel which could have a material adverse effect on our financial condition, results of operations and cash available for distributions to our unitholders.

We are subject to federal, state and local laws and regulations that govern the product quality specifications of the refined petroleum products we purchase, store, transport and sell.

        Various federal, state and local government agencies have the authority to prescribe specific product quality specifications to the sale of commodities. Our business includes such commodities. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce our ability to procure product and our sales volume, require us to incur additional handling costs and/or require the expenditure of capital. For instance, different product specifications for different markets could require additional storage. If we are unable to procure product or recover these costs through increased sales, we may not be able to meet our financial obligations. Failure to comply with these regulations could result in substantial penalties.

We are subject to federal and state environmental regulations which could have a material adverse effect on our retail operations business.

        Our retail operations are subject to extensive federal, state and local laws and regulations, including those relating to the protection of the environment, waste management, discharge of hazardous materials, pollution prevention, as well as laws and regulations relating to public safety and health. Certain of these laws and regulations may require assessment or remediation efforts. Retail operations with underground storage tanks ("USTs") are subject to federal and state regulations and legislation. Compliance with existing and future environmental laws regulating underground storage tanks may require significant capital expenditures and increased operating and maintenance costs. The operation of USTs also poses certain other risks, including damages associated with soil and groundwater contamination. Leaks from USTs which may occur at one or more of our gas stations may impact soil or groundwater and could result in fines or civil liability for us. We may be required to make material expenditures to modify operations, perform site cleanups or curtail operations.

We are subject to federal and state non-environmental regulations which could have an adverse effect on our convenience store business and results of operations.

        Our convenience store business is subject to extensive governmental laws and regulations that include, but are not limited to, legal restrictions on the sale of alcohol, tobacco and lottery products, food safety and health requirements and public accessibility. Furthermore, state and local regulatory agencies have the power to approve, revoke, suspend, or deny applications for and renewals of permits and licenses relating to the sale of alcohol, tobacco and lottery products or to seek other remedies. A violation of or change in such laws and/or regulations could have an adverse effect on our convenience store business and results of operations.

Any terrorist attacks aimed at our facilities and any global and domestic economic repercussions from terrorist activities and the government's response could adversely affect our financial condition, results of operations and cash available for distribution to our unitholders.

        Since the September 11, 2001 terrorist attacks on the United States, the U.S. government has issued warnings that energy assets may be future targets of terrorist organizations. These developments have subjected our operations to increased risks. We incurred costs for providing facility security and

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may incur additional costs in the future with respect to the receipt, storage and distribution of our products. Additional security measures could also restrict our ability to distribute refined petroleum products. Any future terrorist attack on our facilities, or those of our customers, could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

        Terrorist activity could lead to increased volatility in prices for home heating oil, gasoline and other products we sell, which could decrease our customers' demand for these products. Insurance carriers are required to offer coverage for terrorist activities as a result of federal legislation. We purchased this coverage with respect to our property and casualty insurance programs. This additional coverage resulted in additional insurance premiums which could increase further in the future.

We depend on key personnel for the success of our business, and some of those persons face conflicts in the allocation of their time to our business.

        We depend on the services of our senior management team and other key personnel. The loss of the services of any member of senior management or key employee could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. We may not be able to locate or employ on acceptable terms qualified replacements for senior management or other key employees if their services were no longer available. Except with respect to certain of our named executive officers, neither we, our general partner nor any affiliate thereof entered into an employment agreement with, or, except for Eric Slifka, carry key man life insurance on, any member of our senior management team or other key personnel.

        All of the executive officers of our general partner perform services for certain of our affiliates. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Relationship of Management with Global Petroleum Corp. and Alliance Energy LLC."

We depend on unionized labor for the operation of our terminals in Chelsea, Massachusetts and at certain of our terminals in New York and at the facility in Revere, Massachusetts which is controlled and operated by one of our affiliates. Any work stoppages or labor disturbances at these facilities could disrupt our business.

        Any work stoppages or labor disturbances by our unionized labor force at our facilities, including drivers at Chelsea, Massachusetts, could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. In addition, employees who are not currently represented by labor unions may seek representation in the future, and any renegotiation of collective bargaining agreements may result in terms that are less favorable to us.

We rely on our information technology systems to manage numerous aspects of our business, and a disruption of these systems could adversely affect our business.

        We depend on our information technology ("IT") systems to manage numerous aspects of our business and to provide analytical information to management. Our IT systems are an essential component of our business and growth strategies, and a serious disruption to our IT systems could significantly limit our ability to manage and operate our business efficiently. These systems are vulnerable to, among other things, damage and interruption from power loss or natural disasters, computer system and network failures, loss of telecommunication services, physical and electronic loss of data, security breaches and computer viruses. We have a disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an IT systems failure. Any failure or interruption in our IT systems could have a negative impact on our operating results, cause our business and competitive position to suffer and damage our reputation.

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If we fail to maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

        Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If our efforts to maintain internal controls are not successful or if we are unable to maintain adequate controls over our financial processes and reporting in the future or if we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

Risks Related to our Structure

Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.

        As of March 8, 2011, affiliates of our general partner, including directors and executive officers of our general partner, owned 25% of our common units and our 1.06% general partner interest. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, certain directors and officers of our general partner are directors or officers of affiliates of our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Please read "—Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty." These conflicts include, among others, the following situations:

    Our general partner is allowed to take into account the interests of parties other than us, such as affiliates of its members, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

    Affiliates of our general partner may engage in competition with us under certain circumstances. See "—Certain members of the Slifka family and their affiliates may engage in activities that compete directly with us."

    Neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Directors and officers of our general partner's owners have a fiduciary duty to make these decisions in the best interest of such owners which may be contrary to our interests.

    Some officers of our general partner who provide services to us devote time to affiliates of our general partner.

    Our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

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    Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash available for distribution to our unitholders.

    Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces distributable cash flow, or a capital expenditure for acquisitions or capital improvements, which does not, and determination can affect the amount of cash distributed to our unitholders.

    In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

    Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

    Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

    Our general partner intends to limit its liability regarding our contractual and other obligations.

    Our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units.

    Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

        Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement."

Our partnership agreement limits our general partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

    permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of us;

    provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was in our best interests;

    generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general

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      partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

    provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

        By purchasing a common unit, a common unitholder will become bound by the provisions of the partnership agreement, including the provisions described above.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or remove our general partner without its consent, which could lower the trading price of our common units.

        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 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 entirely by its members and not by the unitholders. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. As a result of these limitations, the price at which the common units trade could diminish because of the absence or reduction of a takeover premium in the trading price.

        The unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 662/3% of all outstanding common units voting is required to remove our general partner. As of March 8, 2011, affiliates of our general partner, including directors and executive officers of our general partner, own 25% of our common units.

We may issue additional units without unitholder approval, which would dilute unitholders' ownership interests.

        At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

    our unitholders' proportionate ownership interest in us will decrease;

    the amount of cash available for distribution on each unit may decrease;

    the relative voting strength of each previously outstanding unit may be diminished; and

    the market price of the common units may decline.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units, including sales by our existing unitholders.

        As of March 8, 2011, we had 21,580,563 common units outstanding. A substantial number of our securities may be sold in the future either pursuant to Rule 144 under the Securities Act of 1933 (the "Securities Act") or pursuant to a registration statement filed with the SEC. Rule 144 under the Securities Act provides that after a holding period of six months, non-affiliates may resell restricted securities of reporting companies, provided that current public information for the reporting company is available. After a holding period of one year, non-affiliates may resell without restriction, and affiliates may resell in compliance with the volume, current public information and manner of sale

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requirements of Rule 144. Pursuant to our partnership agreement, members of the Slifka family have registration rights with respect to the common units owned by them.

        Sales by any of our existing unitholders of a substantial number of our common units, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

        In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

An increase in interest rates may cause the market price of our common units to decline.

        Like all equity investments, an investment in our common 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 common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Our general partner has a limited call right that may require 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% 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 and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

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Cost reimbursements due our general partner and its affiliates will reduce cash available for distribution to our unitholders.

        Prior to making any distribution on the common units, we reimburse our general partner and its affiliates for all expenses they incur on our behalf, which is determined by our general partner in its sole discretion. These expenses include all costs incurred by the general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. We are managed and operated by directors and executive officers of our general partner. In addition, the majority of our operating personnel are employees of our general partner. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence." The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates could adversely affect our ability to pay cash distributions to our unitholders.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for our obligations as if he were a general partner if:

    a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or

    a unitholder's right to act with other unitholders to remove or replace the general partner, approve some amendments to our partnership agreement or take other actions under our partnership agreement constitute "control" of our business.

Unitholders may have liability to repay distributions.

        Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to us that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted.

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

        Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and control the decisions taken by the board of directors and officers of our general partner.

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Certain members of the Slifka family and their affiliates may engage in activities that compete directly with us.

        Certain members of the Slifka family and their affiliates are subject to the noncompete provisions in the omnibus agreement. The omnibus agreement does not prohibit certain affiliates of our general partner from owning certain assets or engaging in certain businesses that compete directly or indirectly with us. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement."

Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, our cash available for distribution to unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as us to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced and, therefore, adversely affect the value of an investment in our 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 additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

The 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

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at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. 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 "qualifying income" exception for us to be treated as a partnership for U.S. federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. We are unable to predict whether similar changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in 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 income tax purposes, the minimum quarterly distribution and the target distribution amounts may be adjusted to reflect the impact of that law on us.

We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.

        We conduct all or a portion of our operations of our end-user business through a subsidiary that is organized as a corporation. In addition, through Alliance, as its management agent, the corporation engages in the retail sale of gasoline and operates convenience stores with respect to certain of the stations we acquired from ExxonMobil and collects rents on personal property to dealers at other stations we acquired from ExxonMobil. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is subject to corporate-level tax, which reduces the cash available for distribution to us and, in turn, to unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to unitholders would be further reduced.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any IRS contest will reduce our cash available for distribution to 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 tax 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 the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, because the costs will be borne indirectly by our unitholders and our general partner, the costs of any contest with the IRS will result in a reduction in cash available for distribution.

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 unitholders are treated as partners to whom we allocate taxable income, which could be different in amount than the cash we distribute, unitholders may 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 do not receive any cash distributions from us.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If a unitholder sells his common units, he will recognize a gain or loss equal to the difference between the amount realized and his tax basis in those common units. Because distributions to a

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unitholder in excess of the unitholder's allocable share of our net taxable income decreases the unitholder's tax basis in his common units, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to him if the common units are sold at a price greater than his tax basis in the common units, even if the price he receives is less than his original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if a unitholder sells his units, he may incur a tax liability in excess of the amount of cash he receives 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 employee benefit plans, individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted certain 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 taxable income or loss allocated to our unitholders. It also could affect the gain from a unitholder's sale of common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of our common units.

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 prorate our items of income, gain, loss and deduction between transferors and transferees of our units 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, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. 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.

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A unitholder whose units are loaned 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 a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. 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 common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of 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 taxable gain from our unitholders' sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all 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 significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes but instead, we would be treated as a

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new partnership for federal income tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby the IRS may allow a publicly traded partnership that has technically terminated to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

        In addition to federal income taxes, unitholders will likely be subject to other taxes, including state, local and non-U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. 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, unitholders may be subject to penalties for failure to comply with those requirements. As of December 31, 2010, we conducted business in 16 states, some of which impose a personal income tax as well as an income tax on corporations and other entities. We may own property or conduct business in other states or non-U.S. countries in the future. It is the unitholder's responsibility to file all U.S. federal, state, local and non-U.S. tax returns.

Item 1B.    Unresolved Staff Comments.

        None.

Item 3.    Legal Proceedings.

        Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we do not believe that we are a party to any litigation that will have a material adverse impact on our financial condition, results of operations or cash available for distribution to our unitholders. Except as described below, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we can provide no assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims or that these levels of insurance will be available in the future at economically acceptable prices.

        In connection with the September 2010 acquisition of retail gas stations from ExxonMobil, we assumed certain environmental liabilities with respect to the Acquired Sites (as defined in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview—ExxonMobil Acquisition"). Based on consultations with environmental engineers, our estimated cost of the remediation is expected to be approximately $30.0 million to be expended over an extended period of time. The assumed environmental liabilities include environmental remediation at approximately 70 of the Acquired Sites and future remediation activities at all sites required by applicable federal, state or local law or regulation. Remedial action plans are in place with the applicable state regulatory agencies for the majority of these locations, including plans for soil and groundwater treatment systems at certain sites. We believe that completion of the remediation efforts will not result in material costs in excess of the environmental reserve or have a material impact on our operations. See Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

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        In connection with the June 2010 acquisition of the Warex Terminals, we assumed certain environmental liabilities, including certain ongoing remediation efforts. As a result, we recorded, on an undiscounted basis, a total environmental liability of approximately $1.5 million. We do not believe that completion of the remediation efforts will result in material costs in excess of the environmental reserve or have a material impact on our operations. See Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

        In connection with the November 2007 acquisition of ExxonMobil's Glenwood Landing and Inwood, New York terminals, we assumed certain environmental liabilities, including the remediation obligations under remedial action plans submitted by ExxonMobil to and approved by the New York Department of Environmental Conservation ("NYDEC") with respect to both terminals. As a result, we recorded total environmental liabilities of approximately $1.2 million, of which approximately $0.8 million was paid by us through December 31, 2010. The remaining liability of $0.4 million was recorded as a current liability of $0.3 million and a long-term liability of $0.1 million at December 31, 2010. We have implemented the remedial action plans and do not believe that compliance with the terms thereof will result in material costs in excess of the environmental reserve or have a material impact on our operations. See Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

        In connection with the May 2007 acquisition of ExxonMobil's Albany and Newburgh, New York and Burlington, Vermont terminals, we assumed certain environmental liabilities, including the remediation obligations under a proposed remedial action plan submitted by ExxonMobil to NYDEC with respect to the Albany, New York terminal. As a result, we recorded total environmental liabilities of approximately $8.0 million. In June 2008, we submitted a remedial action work plan to NYDEC, implementing NYDEC's conditional approval of the remedial action plan submitted by ExxonMobil. We responded to NYDEC's requests for additional information and conducted pilot tests for the remediation outlined in the work plan. Based on the results of such pilot tests, we changed our estimate and reduced the environmental liability by $2.8 million during the fourth quarter ended December 31, 2008. Through December 31, 2010, we paid approximately $2.4 million and, at December 31, 2010, this liability had a balance of $2.8 million. In July 2009, NYDEC approved the remedial action work plan, and we signed a Stipulation Agreement with NYDEC to govern implementation of the approved plan. We do not believe that compliance with the terms of the approved remedial action work plan will result in material costs in excess of the environmental reserve or have a material impact on our operations. See Note 9 of Notes to Consolidated Financial Statements included elsewhere in this report.

        In January 2011, the trustee administering the post-bankruptcy litigation trust of Lyondell Chemical Company ("Lyondell") and certain of its affiliates brought an action against us to recover payments totaling approximately $6.0 million made to us by an affiliate of Lyondell that the trustee claims were paid shortly before the Lyondell bankruptcy and at a time when the affiliate was insolvent, allegedly permitting the avoidance or recovery of those payments pursuant to bankruptcy law. We believe that the payments were made by the affiliate in the ordinary course of both its and our business as contemporaneous payment for its receipt of a volume of product of a value equivalent to the payments. The litigation is in its early stages, and we believe we have meritorious defenses. Therefore, no provision for losses has been recorded in connection with this matter.

Item 4.    [Removed and Reserved]

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

        Our common units trade on the New York Stock Exchange under the symbol "GLP." The closing sale price per common unit on March 7, 2011 was $27.11. At the close of business on March 7, 2011, based upon information received from our transfer agent and brokers and nominees, we had 11,265 common unitholders, including beneficial owners of common units held in street name. The following table sets forth the range of the daily high and low sales prices per common unit as quoted on the New York Stock Exchange and the cash distributions per common unit for the periods indicated.

 
  Price Range    
 
 
  Cash Distribution
Per Common Unit(a)
 
 
  High   Low  

2010

                   

Fourth Quarter

  $ 27.79   $ 24.81   $ 0.5000 (b)

Third Quarter

    25.42     21.27     0.4950  

Second Quarter

    23.10     18.00     0.4875  

First Quarter

    26.60     21.10     0.4875  

2009

                   

Fourth Quarter

  $ 27.40   $ 18.51   $ 0.4875  

Third Quarter

    26.00     17.04     0.4875  

Second Quarter

    20.37     11.70     0.4875  

First Quarter

    14.50     8.58     0.4875  

(a)
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a calendar quarter are paid in the following calendar quarter.

(b)
The cash distribution for this quarter was paid on February 14, 2011 to unitholders of record on February 3, 2011.

        On December 9, 2009, our general partner entered into the Third Amended and Restated Agreement of Limited Partnership which amended the Second Amended and Restated Agreement of Limited Partnership, dated May 9, 2007, as amended, to: (i) replace the terms "operating surplus" and "adjusted operating surplus" with the term "distributable cash flow" and thereby eliminate the term "working capital borrowings," (ii) increase the minimum quarterly distribution, prospectively, from $0.4125 to $0.4625 per unit per quarter; and (iii) remove the provisions that previously permitted early conversion of a portion of the subordinated units and restate the provisions governing conversion of the subordinated units using distributable cash flow to test whether we have "earned" the minimum quarterly distribution.

        We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution.

        Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash is all cash on hand on the date of determination of available cash for the quarter;

    less the amount of cash reserves established by our general partner to:

    provide for the proper conduct of our business;

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      comply with applicable law, any of our debt instruments or other agreements; or

      provide funds for distributions to unitholders and to our general partner for any one or more of the next four quarters.

        Conversion of Subordinated Units—Subsequent to December 31, 2010, based upon meeting certain distribution and performance tests provided in our partnership agreement, all 5,642,424 subordinated units have converted to common units.

        We will make distributions of available cash from distributable cash flow for any quarter in the following manner: 98.94% to the common unitholders, pro rata, and 1.06% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages as provided below.

        As holder of the incentive distribution rights, the general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

 
   
  Marginal Percentage
Interest in Distributions
 
 
  Total Quarterly Distribution
Target Amount
  Unitholders   General Partner  

Minimum Quarterly Distribution

  $0.4625   98.94 % 1.06 %

First Target Distribution

  $0.4625   98.94 % 1.06 %

Second Target Distribution

  above $0.4625 up to $0.5375   85.94 % 14.06 %

Third Target Distribution

  above $0.5375 up to $0.6625   75.94 % 24.06 %

Thereafter

  above $0.6625   50.94 % 49.06 %

        The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference from Item 12, "Security Ownership of Certain Beneficial Owners and Management—Equity Compensation Plan Table."

Recent Sales of Unregistered Securities

        None. Please read Item 1, "Business—Recent Developments—Conversion of Subordinated Units" for information on the conversion of our subordinated units into common units.

Issuer Purchases of Equity Securities

        The table below provides information with respect to purchases of our common units made by our general partner on our behalf during the quarter ended December 31, 2010:

Period
  Total Number
Of Units
Purchased
  Average
Price Paid
Per Unit ($)
  Total Number of
Units Purchased as
Part of Publicly
Announced Plans or
Programs(1)
  Maximum Number (or
Approximate Dollar
Value) of Units That May
Yet Be Purchased
Under the Plans or
Programs(1)
 

October 1 – October 31, 2010

                 

November 1 – November 30, 2010

    33,900     25.98     33,900     215,809  

December 1 – December 31, 2010

                 

(1)
On May 7, 2009, the board of directors of our general partner announced that it authorized the repurchase of our common units for the purpose of meeting our general partner's anticipated obligations to deliver common units under the LTIP and meeting the general partner's obligations under existing employment agreements and other employment related obligations of the general

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    partner. We are authorized to acquire up to 445,000 of our common units in the aggregate, over an extended period of time, consistent with the general partner's obligations under the LTIP and employment agreements. Common units may be repurchased from time to time in open market transactions, including block purchases, or in privately negotiated transactions. Such authorized unit repurchases may be modified, suspended or terminated at any time, and are subject to price, economic and market conditions, applicable legal requirements and available liquidity.

Item 6.    Selected Financial Data.

        The following table presents selected historical financial and operating data of Global Partners LP for the years and as of the dates indicated. The selected historical financial data is derived from the historical consolidated financial statements of Global Partners LP.

        This table should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements of Global Partners LP and the notes thereto included elsewhere in this report. In addition, this table presents non-GAAP financial measures which we use in our business. These measures are not calculated or presented in accordance with generally accepted accounting principles in the United States ("GAAP"). We explain these measures and present reconciliations to their most directly

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comparable financial measures calculated in accordance with GAAP in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
  Year Ended December 31,  
 
  2010   2009   2008   2007   2006  
 
  (dollars in millions except per unit amounts)
 

Statement of Income Data:

                               

Sales

  $ 7,801.5   $ 5,818.4   $ 9,019.1   $ 6,757.8   $ 4,472.4  

Cost of sales

    7,634.8     5,668.6     8,899.3     6,630.8     4,359.2  
                       

Gross profit

    166.7     149.8     119.8     127.0     113.2  

Selling, general and administrative expenses

    66.1     61.0     42.1     45.5     43.0  

Operating expenses

    47.8     35.0     31.8     27.7     22.2  

Amortization expense

    3.5     3.0     2.9     2.3     1.5  
                       
 

Total operating costs and expenses

    117.4     99.0     76.8     75.5     66.7  
                       

Operating income

    49.3     50.8     43.0     51.5     46.5  

Interest expense

    (22.3 )   (15.2 )   (20.8 )   (17.4 )   (11.9 )

Other income

                    0.5  

Gain on sale of investment(1)

                14.1      
                       

Income before income tax expense

    27.0     35.6     22.2     48.2     35.1  

Income tax expense

        (1.5 )   (1.1 )   (1.2 )   (1.6 )
                       

Net Income

    27.0     34.1     21.1     47.0     33.5  

Less: General partner's interest in net income

    (0.6 )   (0.8 )   (0.6 )   (1.0 )   (0.7 )
                       

Limited partners' interest in net income

  $ 26.4   $ 33.3   $ 20.5   $ 46.0   $ 32.8  
                       

Basic net income per limited partner unit(2)

  $ 1.61   $ 2.56   $ 1.57   $ 2.38   $ 2.46  
                       

Diluted net income per limited partner unit(2)

  $ 1.59   $ 2.51   $ 1.57   $ 2.38   $ 2.46  
                       

Basic weighted average limited partner' units outstanding

    16.3     13.0     13.1     12.4     11.3  
                       

Diluted weighted average limited partner' units outstanding

    16.6     13.3     13.1     12.4     11.3  
                       

Cash Flow Data:

                               

Net cash (used in) provided by

                               
 

Operating activities

  $ (87.2 ) $ (61.1 ) $ 99.2   $ (115.0 ) $ (54.5 )
 

Investment activities

    (263.0 )   (9.1 )   (11.5 )   (136.5 )   (12.4 )
 

Financing activities

    351.9     69.9     (88.9 )   249.7     69.0  

Other Financial Data:

                               

EBITDA(5)

  $ 72.4   $ 66.7   $ 58.1   $ 75.2   $ 51.5  

Adjusted EBITDA(3)

    72.4     66.7     58.1     61.1     51.5  

Distributable cash flow(4)

    46.0     45.4     34.1     38.6     36.0  

Capital expenditures(5)

    14.7     9.1     11.5     13.7     5.9  

Cash distributions per limited partner unit(6)

    1.96     1.95     1.95     1.87     1.72  

Operating Data:

                               

Normal heating degree days(7)

    5,630     5,630     5,630     5,630     5,630  

Actual heating degree days

    5,049     5,656     5,426     5,656     5,007  

Variance from normal heating degree days

    (10)%     1%     (4)%     1%     (11)%  

Variance from prior year actual degree days

    (11)%     4%     (4)%     13%     (15)%  

Total gallons sold (in millions)

    3,650     3,404     3,550     3,288     2,486  

Variance in volume sold from prior year

    7%     (4)%     8%     32%     (7)%  

Balance Sheet Data (at period end):

                               

Cash and cash equivalents

  $ 2.4   $ 0.6   $ 0.9   $ 2.1   $ 3.9  

Property and equipment, net

    422.7     159.3     162.0     161.7     31.7  

Total assets

    1,672.3     1,052.7     889.3     1,159.2     638.9  

Total debt

    786.7     533.8     433.5     496.2     272.3  

Total liabilities

    1,395.5     895.3     745.8     998.9     535.7  

Equity

    276.8     157.4     143.5     160.3     103.2  

(1)
We sold our investment in NYMEX Holdings, Inc. along with our NYMEX seats for approximately $15.3 million and realized a gain of approximately $14.1 million for the year ended December 31, 2007.

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(2)
See Note 2 of Notes to Consolidated Financial Statements included elsewhere in this report for net income per limited partner unit calculation.

(3)
Earnings before interest, taxes, depreciation and amortization ("EBITDA") and adjusted EBITDA are non-GAAP financial measures which are discussed under "Results of Operations—Evaluating Our Results of Operations" and reconciled to their most directly comparable GAAP financial measures in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." Adjusted EBITDA is EBITDA less the $14.1 million gain we realized on the sale of our investment in NYMEX Holdings, Inc. along with our NYMEX seats for the year ended December 31, 2007.

(4)
Distributable cash flow is a non-GAAP financial measure which is discussed under "Results of Operations—Evaluating Our Results of Operations" and reconciled to its most directly comparable GAAP financial measures in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

(5)
Capital expenditures are discussed in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

(6)
Cash distributions declared in one calendar quarter are paid in the following calendar quarter. This amount is based on cash distributions paid during each respective year. See Note 14 of Notes to Consolidated Financial Statements included elsewhere in this report.

(7)
Degree days is an industry measurement of temperature designed to evaluate energy demand and consumption which is further discussed under "Results of Operations—Evaluating Our Results of Operations" in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

        The following discussion and analysis of financial condition and results of operations of Global Partners LP should be read in conjunction with the historical consolidated financial statements of Global Partners LP and the notes thereto included elsewhere in this report.

Overview

        We own, control or have access to one of the largest terminal networks of refined petroleum products in the Northeast. We are one of the largest wholesale distributors of gasoline, distillates (such as home heating oil, diesel and kerosene), residual oil and renewable fuels (such as ethanol) to wholesalers, retailers and commercial customers in the New England states and New York. We own and supply fuel to 190 Mobil-branded retail gas stations (38 leased properties and 152 fee properties) in New England and supply Mobil-branded fuel to an additional 31 independently-owned stations. In 2010, we sold approximately $7.8 billion of refined petroleum products and small amounts of natural gas and renewable fuels. In addition, we had revenues of approximately $16.1 million, primarily from convenience store sales at our directly operated stores and gas station rental income.

        We purchase our refined petroleum products primarily from domestic and foreign refiners, major and independent oil companies and trading companies and sell these products in two segments, Wholesale and Commercial. Like most independent marketers of refined petroleum products, we base our pricing on spot physical prices and routinely use the NYMEX or other derivatives to hedge our commodity risk inherent in buying and selling energy commodities. Through the use of regulated exchanges or derivatives, we maintain a position that is substantially balanced between purchased volumes and sales volumes or future delivery obligations. We earn a margin by selling the product for physical delivery to third parties.

        Our products primarily include unbranded and Mobil-branded gasoline, distillates and residual oil. We sell gasoline to unbranded and Mobil-branded retail gasoline stations and other resellers of transportation fuels. The distillates we sell are used primarily for fuel for trucks and off-road construction equipment and for space heating of residential and commercial buildings. We sell residual oil to major housing units, such as public housing authorities, colleges and hospitals and large industrial facilities that use processed steam in their manufacturing processes. In addition, we sell bunker fuel, which we can custom blend, to cruise ships, bulk carriers and fishing fleets. We have increased our sales in the non-weather sensitive components of our business, such as transportation fuels; however, we are still subject to the impact that warmer weather conditions may have on our home heating oil and residual oil sales.

        Our business is divided into three operating segments:

    Wholesale.  This segment includes sales of unbranded and Mobil-branded gasoline, distillates, residual oil and small amounts of renewable fuels to retail gasoline stations and other resellers of transportation fuels, home heating oil retailers and wholesale distributors.

    Commercial.  This segment includes sales and deliveries of unbranded gasoline, distillates, residual oil and small amounts of natural gas and renewable fuels to end user customers in the public sector and to large commercial and industrial end user customers. In the case of commercial and industrial end user customers, we sell our products primarily either through a competitive bidding process or through contracts of various terms. Our commercial segment sales also include sales of Mobil-branded gasoline to end users at our directly operated gas

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      stations. This segment also purchases, custom blends, sells and delivers bunker fuel and diesel to cruise ships, bulk carriers and fishing fleets generally by barges.

    Other.  This segment includes convenience store, car wash and other ancillary sales and rental income from the Dealer Leased Sites (defined below). Please read "—ExxonMobil Acquisition."

        Our business is substantially comprised of purchasing, storing, terminalling and selling refined petroleum products. In a contango market (when product prices for future deliveries are higher than for current deliveries), we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers at higher prices in the future. In a backward market (when product prices for future deliveries are lower than current deliveries), we attempt to minimize our inventories to reduce commodity risk and maintain or increase net product margins. See Part I, Item 1A, "Risk Factors," for additional information related to commodity risk.

        This section identifies certain risks and certain economic or industry-wide factors that may affect our financial performance and results of operations in the future, both in the short term and in the long term. Our results of operations and financial condition depend, in part, upon the following:

    The condition of credit markets may adversely affect our liquidity.  In the recent past, world financial markets experienced a severe reduction in the availability of credit. Although we were not negatively impacted by this condition, possible negative impacts in the future could include a decrease in the availability of borrowings under our credit agreement, increased counterparty credit risk on our derivatives contracts and our contractual counterparties requiring us to provide collateral. In addition, we could experience a tightening of trade credit from our suppliers.

    We commit substantial resources to pursuing acquisitions, though there is no certainty that we will successfully complete any acquisitions or receive the economic results we anticipate from completed acquisitions.  Consistent with our business strategy, we are continuously engaged in discussions with potential sellers of terminalling, storage and/or marketing assets and related businesses. Our growth largely depends on our ability to make accretive acquisitions. We may be unable to make such accretive acquisitions for a number of reasons, including, but not limited to, the following: (1) we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts; (2) we are unable to raise financing for such acquisitions on economically acceptable terms; or (3) we are outbid by competitors. In addition, we may consummate acquisitions that at the time of consummation we believe will be accretive, but that ultimately may not be accretive. If any of these events were to occur, our future growth would be limited. We can give no assurance that our acquisition efforts will be successful or that any such acquisition will be completed on terms that are favorable to us.

    Our financial results are generally better in the first and fourth quarters of the calendar year.  Demand for some refined petroleum products, specifically home heating oil and residual oil for space heating purposes, is generally higher during November through March than during April through October. We obtain a significant portion of these sales during these winter months. Therefore, our results of operations for the first and fourth calendar quarters are generally better than for the second and third quarters. With lower cash flow during the second and third calendar quarters, we may be required to borrow money in order to maintain current levels of distributions to our unitholders.

    Warmer weather conditions could adversely affect our results of operations and financial condition.  Weather conditions generally have an impact on the demand for both home heating oil and

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      residual oil. Because we supply distributors whose customers depend on home heating oil and residual oil for space heating purposes during the winter, warmer-than-normal temperatures during the first and fourth calendar quarters in the Northeast can decrease the total volume we sell and the gross profit realized on those sales.

    Energy efficiency, new technology and alternative fuels could reduce demand for our products.  Increased conservation and technological advances have adversely affected the demand for home heating oil and residual oil. Consumption of residual oil has steadily declined over the last three decades. We could face additional competition from alternative energy sources as a result of future government-mandated controls or regulation further promoting the use of cleaner fuels. End users who are dual-fuel users have the ability to switch between residual oil and natural gas. Other end users may elect to convert to natural gas. During a period of increasing residual oil prices relative to the prices of natural gas, dual-fuel customers may switch and other end users may convert to natural gas. Residential users of home heating oil may also convert to natural gas. Such switching or conversion could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders. In addition, new technologies and alternative fuel sources, such as electric, hybrid or battery powered motor vehicles, could reduce the demand for gasoline and adversely impact our gasoline sales. A reduction in gasoline sales could have an adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.

    Our financial condition and results of operations are influenced by the overall forward market for refined petroleum products, and increases and/or decreases in the prices of refined petroleum products may adversely impact the amount of borrowing available for working capital under our credit agreement, which credit agreement has borrowing base limitations and advance rates, as well as access to trade credit.  Results from our purchasing, storing, terminalling and selling operations are influenced by prices for refined petroleum products, pricing volatility and the market for such products. Prices in the overall forward market for refined petroleum products may impact our ability to execute advantageous purchasing opportunities. In a contango market (when product prices for future deliveries are higher than for current deliveries), we may use our storage capacity to improve our margins by storing products we have purchased at lower prices in the current market for delivery to customers at higher prices in the future. In a backward market (when product prices for future deliveries are lower than current deliveries), we attempt to minimize our inventories to reduce commodity risk and maintain or increase net product margins. When prices for refined petroleum products rise, some of our customers may have insufficient credit to purchase supply from us at their historical purchase volumes, and their customers, in turn, may adopt conservation measures which reduce consumption, thereby reducing demand for product. Furthermore, when prices increase rapidly and dramatically, we may be unable to promptly pass our additional costs on to our customers, resulting in lower margins for us which could adversely affect our results of operation. Lastly, higher prices for refined petroleum products may (1) diminish our access to trade credit support and/or cause it to become more expensive and (2) decrease the amount of borrowings available for working capital under our credit agreement as a result of total available commitments, borrowing base limitations and advance rates thereunder. In addition, when prices for refined petroleum products decline, our exposure to risk of loss in the event of nonperformance by our customers of our forward contracts may be increased as they and/or their customers may breach their contracts and purchase refined petroleum products at the then lower spot and/or retail market price. Furthermore, lower prices for refined petroleum products may diminish the amount of borrowings available for working capital under our working capital revolving credit facility as a result of borrowing base limitations.

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    Changes in government usage mandates and tax credits could adversely affect the availability and pricing of ethanol, which could negatively impact our gasoline sales.  Future demand for ethanol will be largely dependent upon the economic incentives to blend based upon the relative value of gasoline and ethanol, taking into consideration the Volumetric Ethanol Excise Tax Credit (the "blender's credit") and the EPA's regulations on the Renewable Fuels Standard ("RFS") program and oxygenate blending requirements. A reduction or waiver of the RFS mandate or the oxygenate blending requirements or the failure to extend the blender's credit could adversely affect the availability and pricing of ethanol, which in turn could adversely affect our future gasoline and ethanol sales. Please read Item 1, "Business—Recent Developments—Ethanol and Rail Expansion Project."

    New, stricter environmental laws and regulations could significantly increase our costs, which could adversely affect our results of operations and financial condition.  Our operations are subject to federal, state and local laws and regulations regulating product quality specifications and other environmental matters. The trend in environmental regulation is towards more restrictions and limitations on activities that may affect the environment. Our business may be adversely affected by increased costs and liabilities resulting from such stricter laws and regulations. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. However, there can be no assurances as to the timing and type of such changes in existing laws or the promulgation of new laws or the amount of any required expenditures associated therewith.

    ExxonMobil Acquisition

        On September 30, 2010, we completed our acquisition of retail gas stations and supply rights from ExxonMobil for cash consideration of approximately $202.3 million, plus the assumption of certain environmental liabilities (the "Acquisition"). The Acquisition was completed in multiple phases from September 8 through September 30, 2010.

        The following is a summary of the Acquisition and certain matters relating to our operation of the acquired assets and rights. Information regarding results and operations of the Sites (as defined below) prior to the Acquisition, including rents, real estate taxes, sales and salaries and benefits, is based on available information, including certain information provided by the seller.

        Assets Acquired and Liabilities Assumed—The Acquisition included the purchase of the following assets from ExxonMobil:

    148 stations leased to and operated by dealers (the "Dealer Leased Sites"). 130 of the Dealer Leased Sites are located in Massachusetts, 9 are located in Rhode Island and 9 are located in New Hampshire. 124 of the Dealer Leased Sites are owned by us. 24 of the Dealer Leased Sites are leased by us pursuant to existing lease agreements with third-party landlords assigned to and assumed by us and subleased by dealers.

      Assuming we exercise available renewal terms, the leases with third-party landlords for the 24 Dealer Leased Sites leased by us expire between 2011 and 2033, with an average remaining lease term of approximately 12 years. The rent paid in 2009 for the 24 leased Dealer Leased Sites was approximately $1.6 million and approximately $360,000 was paid for real estate taxes. The real estate taxes paid in 2009 for the 124 owned Dealer Leased Sites was approximately $2.0 million. Subject to applicable rent increases under the terms of the leases for the 24 leased Dealer Leased Sites, and any real estate tax increases imposed by applicable taxing authority, we expect to incur comparable rent and real estate tax expenses in connection with the future operation of the Dealer Leased Sites.

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      Each of the Dealer Leased Sites are leased or subleased, as applicable, to and operated by dealers pursuant to existing franchise agreements assigned to and assumed by us. The franchise agreements for the Dealer Leased Sites are generally for three-year terms with varying expiration dates and contain renewal terms pursuant to and governed by applicable federal laws. In 2009, the rents paid by dealers for the 148 Dealer Leased Sites were approximately $16.8 million. Subject to rent increases under the terms of the franchise agreements for the 148 Dealer Leased Sites, and any changes in rent contained in any renewal franchise agreements executed for the 148 Dealer Leased Sites, we expect to receive similar rents in connection with the future operation of the Dealer Leased Sites.

      From the Dealer Leased Sites, we receive revenues pursuant to the terms of the franchise agreements from (a) rent paid by the dealers, and (b) the wholesale supply of Mobil-branded gasoline and diesel fuel sold to the Dealer Leased Sites. All revenues at the Dealer Leased Sites relating to (a) the sale of Mobil-branded gasoline and diesel fuels to retail end-users, and (b) convenience store, car wash and other ancillary sales are for the account of the dealer who leases and operates the location. All station-level employees of each Dealer Leased Site are employees of the dealer who leases and operates the location.

    42 stations directly operated by a management company as discussed below (the "Company Operated Sites" and, together with the Dealer Leased Sites, the "Acquired Sites"). Simultaneously with the Acquisition, the Company Operated Sites were transferred by us to GMG, our wholly owned subsidiary. 27 of the Company Operated Sites are located in Massachusetts, 6 are located in Rhode Island and 9 are located in New Hampshire. 28 of the Company Operated Sites are owned by GMG. 14 of the Company Operated Sites are leased by GMG pursuant to existing lease agreements with third-party landlords assigned to and assumed by GMG.

      Assuming exercise by GMG of available renewal terms, the leases with third-party landlords for the 14 Company Operated Sites leased by us expire between 2013 and 2038, with an average remaining lease term of approximately 12 years. The rent paid in 2009 for the 14 leased Company Operated Sites was approximately $1.5 million and approximately $330,000 was paid for real estate taxes. The real estate taxes paid in 2009 for the 28 owned Company Operated sites was approximately $728,000. Subject to applicable rent increases under the terms of the leases for the 14 leased Company Operated Sites, and any real estate tax increases imposed by applicable taxing authority, we expect to incur comparable rent and real estate tax expenses in connection with the future operation of the Company Operated Sites.

      All of the Company Operated Sites have convenience stores ranging in size from 900 to 3,900 square feet, 38 of which are operated under the On the Run flag (see "—Management Agreements"). 36 of the Company Operated Sites are open 24 hours per day. All of the Company Operated Sites are licensed lottery agents in their respective states. The 9 Company Operated Sites in New Hampshire are licensed to sell beer and wine. 20 of the Company Operated Sites have car washes on site. The Company Operated Sites averaged convenience store sales in 2009 of approximately $1.0 million per site.

      From the Company Operated Sites, we will receive revenues from (a) the wholesale supply of Mobil-branded gasoline and diesel fuel to the Company Operated Sites, (b) the sale of Mobil-branded gasoline and diesel fuel to retail end-users, and (c) convenience store, car wash and other ancillary sales. All station-level employees of a Company Operated Sites are employees of GMG's management agent, as discussed below.

    The right to supply Mobil-branded fuel to an additional 31 stations that are owned and operated by independent dealers (the "Dealer Owned Sites" and, together with the Acquired Sites, the "Sites"). Each of the Dealer Owned Sites is supplied fuel pursuant to an existing supply

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      agreement assigned to and assumed by us. 22 of the Dealer Owned Sites are located in Massachusetts, 7 are located in Rhode Island and 2 are located in New Hampshire. The supply agreements for the Dealer Owned Sites expire between 2011 and 2015, and we intend to pursue renewals of these agreements as they mature.

      From the Dealer Owned Sites, we will receive revenues solely from the wholesale supply of Mobil-branded gasoline and diesel fuel to the Dealer Owned Sites. All revenues at the Dealer Owned Sites relating to (a) the sale of Mobil-branded gasoline and diesel fuels to retail end-users, and (b) convenience store, car wash and other ancillary sales are for the benefit of the dealer who owns and operates the location. All station-level employees of each Dealer Operated Site are employees of the independent dealer who owns the location.

      In 2009, the Dealer Owned Sites, together with the Dealer Leased Sites, sold approximately 275 million gallons of gasoline and diesel fuel. Also in 2009, the Company Operated Sites sold approximately 95 million gallons of gasoline and diesel fuel.

        We believe the Acquired Sites are premier locations and have been well maintained. All underground storage tank systems and related dispensing equipment were inspected by us and environmental engineers as part of due diligence activities prior to consummation of the Acquisition and are believed to be in compliance in all material respects with all applicable federal, state and local underground storage tank laws and regulations. Our policy will be to replace underground motor fuel storage tanks at approximately 30 years of age. The average tank age of the underground storage tanks at the Acquired Sites is approximately 19.5 years. We do not own the underground storage tanks or other dispensing equipment at the Dealer Owned Sites. Based on a 30-year average life replacement cycle, we expect to replace approximately 18% of the tanks in the next 5 years. All of the motor fuel storage tanks at the Acquired Sites are constructed of fiberglass reinforced plastic, with approximately 2/3 of the tanks double walled. All tanks at the Acquired Sites are equipped with automatic tank gauges which are remotely monitored for leak detection purposes.

        Pursuant to the BFA (as defined below), we must maintain all buildings at each of the Acquired Sites, and must ensure that the operators maintain all buildings at each of the Dealer Owned Sites, in compliance with all applicable fire, building and zoning codes and ordinances, in a clean condition free of debris, trash and fire hazards, and in accordance with detailed and rigorous ExxonMobil brand imaging requirements. We believe that each of the Sites is in compliance in all material respects with each of these requirements.

        In addition to the contractual obligations assumed by us as described above, we assumed certain environmental liabilities with respect to the Acquired Sites. The assumed environmental liabilities include on-going environmental remediation at approximately 70 of the Acquired Sites and future remediation activities required by applicable federal, state or local law or regulation. Based on consultations with environmental engineers, our estimated cost of the remediation is expected to be approximately $30.0 million to be expended over an extended period of time.

        We contemplate potential sales of Acquired Sites to franchise dealers and other third parties, and the possible lease of Acquired Sites to commissioned agents. A "commissioned agent" is a person who leases and operates the convenience store as an independent operator, with all convenience store revenues for the agent's account. In addition, the agent receives a commission on a per gallon basis for the sale of fuel products owned, priced and sold by us.

        Brand Fee Agreement—In connection with the Acquisition, we and ExxonMobil entered into a 15-year Brand Fee Agreement (the "BFA"), which entitles us to (a) operate each of the Company Operated Sites under the Mobil-branded trade name and related trade logos (the "Mobil Flag"), (b) allow the Dealer Leased Sites and the Dealer Owned Sites to be operated under the Mobil Flag, (c) subject to ExxonMobil's approval, brand additional service stations (whether company operated,

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dealer leased or dealer owned) in Massachusetts, Rhode Island, New Hampshire, Maine and Vermont (collectively, the "BFA States") under the Mobil Flag, and (d) supply Mobil-branded motor fuel to the Sites and other Mobil-branded stations in the BFA States. We are responsible for complying and ensuring compliance by all third parties purchasing Mobil-branded motor fuel from us within the BFA States, with all of ExxonMobil's branded facility requirements, brand image specifications and restrictions and minimum service standards with respect to the use of the Mobil Flag and the sale of Mobil-branded motor fuel. In addition, on and after June 1, 2011, we will have similar rights and responsibilities with respect to the Exxon branded trade name and related trade logos (the "Exxon Flag") in the BFA States.

        We are responsible for securing our own wholesale fuel supply, including sourcing and delivery of motor fuel and ExxonMobil proprietary additives, arranging for storage and distribution at and from bulk storage facilities and installing any necessary additive injection systems, and providing dispatch and distribution systems for delivery of fuel to the Sites and any other Mobil-branded station supplied by us in the BFA States during the term of the BFA. We are also responsible for ensuring that any Mobil-branded motor fuel distributed by us within the BFA States meets ExxonMobil's specifications and quality assurance requirements for Mobil-branded motor fuel, as such specifications and requirements may be changed by ExxonMobil from time to time, as well as all applicable federal, state and local laws and regulations. Except for a brief transition period, ExxonMobil will not supply motor fuels to us within the BFA States. The Acquisition did not include any of ExxonMobil's existing supply arrangements, terminal assets, rolling stock or other storage and distribution system components.

        Securing wholesale fuel supply is part of our core business. Our products come from some of the major energy companies in the world. Cargos are sourced from the United States, Canada, South America, Europe, Russia and occasionally from Asia. During 2010, we purchased an average of approximately 238,000 barrels per day of refined petroleum products from approximately 115 suppliers. In 2010, our top ten suppliers accounted for approximately 60% of product purchases. We enter into supply agreements with these suppliers on a term basis or a spot basis.

        We will utilize our existing terminal network to supply the Sites. This terminal network includes bulk terminals owned by us or at which we maintain dedicated storage as well as throughput or exchange agreements at other bulk terminals. Throughput arrangements allow storage of product at terminals owned by others. We can load product at these terminals, and pay the owners of these terminals fees for services rendered in connection with the receipt, storage and handling of such product. Exchange agreements also allow us to take delivery of product at a terminal or facility that is not owned or leased. An exchange is a contractual agreement where the parties exchange product at their respective terminals or facilities. For example, we receive product that is owned by the exchange partner from such party's facility or terminal, and we deliver the same volume of product to such party out of one of the terminals in our terminal network. Initially, we intend to supply the Sites pursuant to throughput agreements at two bulk terminals and an exchange agreement at one bulk terminal, each of which currently have the necessary Mobil proprietary additive available. We can supply the Sites using additional bulk terminals in our terminal network, subject to potential modifications to accommodate the storage and injection of Mobil proprietary additive as required by the BFA. Consistent with our other operations, the bulk supply required for the Sites and other locations supplied pursuant to the BFA are substantially hedged through futures contracts and swap agreements.

        Pursuant to the BFA, we have the right (but not the obligation) to continue operating the Sites under the Mobil Flag. In addition, on and after June 1, 2011, we will have similar rights with respect to the Exxon Flag. We will pay a fee of approximately $9.0 million to ExxonMobil in 2011 for this right, plus an additional amount in the event additional sites are branded Mobil or Exxon or supplied Mobil or Exxon branded fuel by us pursuant to the BFA. Initially, we intend to continue operating the Sites under the Mobil brand, although we have the right to rebrand the Sites to another major gasoline

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brand or to operate the Sites as unbranded stations. In the event we rebrand any of the Sites to another major gasoline brand or to an unbranded station, the BFA fee will not decrease.

        ExxonMobil has agreed to provide credit card processing services for the Sites and any other stations Mobil-branded or supplied by us in the BFA States pursuant to the BFA. We are responsible for providing our own marketing and promotion efforts in support of the Mobil and Exxon brands within the BFA States. We expect to benefit from national promotions of the Mobil (and, after June 1, 2011, Exxon) brand by ExxonMobil. We are responsible for providing our own customer service operations to respond to consumer complaints or concerns regarding the operation of the Sites and other stations Mobil-branded or supplied by us under the BFA. In addition, ExxonMobil operates and offers a variety of incentive and rebate programs for franchise dealers and other wholesale distributors which, prior to the Acquisition, were available to the Sites. Under the BFA, these programs are not available to us, and we will be responsible for developing, offering and administering any such program we wish to offer to any of the Sites.

        Pursuant to the BFA, we also have the ability to provide Mobil-branded fuels to other authorized Mobil distributors in the BFA States. As of March 1, 2011, we began supplying several such distributors, including Alliance. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence."

        Management Agreements—In connection with the Acquisition, Global Companies LLC and GMG entered into Facilities Management Agreements (each, a "Management Agreement") with Alliance with respect to all of the Sites. Alliance is approximately 95% owned by members of the Slifka family, who also own our general partner. Each Management Agreement is for an initial term continuing through September 30, 2013. Either party to each Management Agreement may extend the term for consecutive additional one-year terms by giving written notice of its election to extend the term not less than 24 months prior to the expiration of the then current term, subject to the parties' mutual agreement on the management fee for such extension.

        Pursuant to the Management Agreements, Alliance will supervise and direct the day-to-day management and operations of the Sites for an aggregate annual management fee of $2.6 million, commencing October 1, 2010. Alliance will manage the operations of the Sites in accordance with annual budgets to be approved by Global Companies LLC and GMG, respectively. In addition to the annual management fee, Global Companies LLC and GMG are responsible for reimbursing Alliance for certain direct overhead expenses related to the operations of the Sites, including costs relating to the employees directly employed to manage and operate the Sites and a portion of the costs relating to certain administrative personnel of Alliance as may be approved by Global Companies LLC and/or GMG, in accordance with the Management Agreements and the approved annual budgets. In the event that the number or type of Mobil or Exxon branded stations in the BFA States changes, the annual management fee and reimbursed direct overhead expenses may be adjusted as the parties mutually agree.

        In connection with the Acquisition, all of ExxonMobil's station-level employees at the Company Operated Sites and ExxonMobil's 13 field supervisory and support employees responsible for the Sites were hired by Alliance. The aggregate cost of salary and benefits in 2009 for station-level employees at the Company Operated Sites was approximately $9.5 million, exclusive of field supervisory and support employees. As we may operate the Company Operated Sites in a manner different than ExxonMobil, the aggregate cost of salary and benefits for station-level employees at the Company Operated Sites may be greater or less than the amounts incurred by ExxonMobil. All matters pertaining to the employment, supervision, compensation, promotion, and discharge of such employees are the responsibility of Alliance. Pursuant to the Management Agreements, Alliance is required to indemnify Global Companies LLC and GMG from and against any and all claims and damages of any nature whatsoever arising out of or incidental to Alliance's performance of its responsibilities under the

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Management Agreements caused by or due to fraud, gross negligence, willful misconduct or a material breach by Alliance of any provision of the Management Agreements. Alliance's aggregate liability is capped at $5.0 million, over and above the utilization of any and all insurance proceeds.

        In addition, pursuant to the Management Agreements, Alliance is providing certain accounting, tax, information technology, legal, maintenance, environmental and regulatory, dispatch, credit, human resource, construction and other services not acquired as part of the Acquisition. Additional accounting, tax, information technology, legal, environmental and regulatory, credit and other services not acquired as part of the Acquisition and not otherwise provided by Alliance pursuant to the Management Agreements will be provided by us. In addition, we will be solely responsible for providing all necessary employees and services relating to any wholesale fuel supply, including sourcing and delivery of physical product and ExxonMobil proprietary additives, and arranging for storage at and distribution from bulk storage facilities and installing any necessary additive injection systems, as these services were not acquired as part of the Acquisition. The ExxonMobil employees who previously provided the services being provided by us with respect to these activities were not available for hire as part of the Acquisition.

        Alliance, as management agent for GMG, has obtained the right to continue operating 38 of the Company Operated Sites under the current On the Run convenience store brand, as the Acquisition did not include ExxonMobil's rights to use this brand name. We have the right to rebrand the convenience stores at the Company Operated Sites to another brand in the future. In addition, we did not acquire any of ExxonMobil's existing supply contracts with convenience store vendors, and we have entered into new arrangements with suppliers to stock the convenience stores at the Company Operated Sites. Subject to approval under the BFA, dealers at Dealer Leased Sites and at Dealer Owned Sites are responsible for obtaining any necessary rights to any convenience store brand name for these sites as well as entering into any desired supply contracts with convenience store vendors directly.

        Other ExxonMobil Relationships—ExxonMobil has long-term throughput contracts with us for the use of five refined petroleum products terminals acquired from ExxonMobil in 2007. We supply refined petroleum products to ExxonMobil at four of these terminals. ExxonMobil is also a supplier of refined petroleum products to us at other locations. ExxonMobil accounted for approximately 19%, 22% and 20% of our consolidated sales for the years ended December 31, 2010, 2009 and 2008, respectively.

Results of Operations

        Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include: (1) net product margin, (2) gross profit, (3) selling, general and administrative expenses ("SG&A"), (4) operating expenses, (5) degree days, (6) net income per diluted limited partner unit, (7) EBITDA and (8) distributable cash flow.

        We view net product margin as an important performance measure of the core profitability of our operations. We review net product margin monthly for consistency and trend analysis. We define net product margin as our sales minus product costs. Sales primarily include sales of unbranded and Mobil-branded gasoline, distillates, residual oil, small amounts of natural gas and renewable fuels and convenience store sales and gas station rental income. Product costs include the cost of acquiring the refined petroleum products, natural gas and renewable fuels that we sell and all associated costs including shipping and handling costs to bring such products to the point of sale. We also look at net product margin on a per unit basis (net product margin divided by volume). Net product margin is a non-GAAP financial measure used by management and external users of our consolidated financial statements to assess our business. Net product margin should not be considered as an alternative to net

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income, operating income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our net product margin may not be comparable to net product margin or a similarly titled measure of other companies.

        We define gross profit as our sales minus product costs and terminal depreciation expense allocated to cost of sales. Sales primarily include sales of unbranded and Mobil-branded gasoline, distillates, residual oil and small amounts of natural gas and renewable fuels. Product costs include the cost of acquiring the refined petroleum products, natural gas and renewable fuels that we sell and all associated costs to bring such products to the point of sale.

        Our SG&A expenses include, among other things, marketing costs, corporate overhead, employee salaries and benefits, pension and 401(k) plan expenses, discretionary bonuses, non-interest financing costs, professional fees and information technology expenses. Employee-related expenses including employee salaries, discretionary bonuses and related payroll taxes, benefits, and pension and 401(k) plan expenses are paid by our general partner which, in turn, is reimbursed for these expenses by us.

        Operating expenses are costs associated with the operation of the terminals and gasoline stations used in our business. Lease payments and storage expenses, maintenance and repair, utilities, taxes, labor and labor-related expenses comprise the most significant portion of our operating expenses. These expenses remain relatively stable independent of the volumes through our system but fluctuate slightly depending on the activities performed during a specific period.

        A "degree day" is an industry measurement of temperature designed to evaluate energy demand and consumption. Degree days are based on how far the average temperature departs from a human comfort level of 65°F. Each degree of temperature above 65°F is counted as one cooling degree day, and each degree of temperature below 65°F is counted as one heating degree day. Degree days are accumulated each day over the course of a year and can be compared to a monthly or a long-term (multi-year) average, or normal, to see if a month or a year was warmer or cooler than usual. Degree days are officially observed by the National Weather Service and officially archived by the National Climatic Data Center. For purposes of evaluating our results of operations, we use the normal heating degree day amount as reported by the National Weather Service at its Logan International Airport station in Boston, Massachusetts.

        We use net income per diluted limited partner unit to measure our financial performance on a per-unit basis. Net income per diluted limited partner unit is defined as net income, divided by the weighted average number of outstanding diluted common and subordinated units, or limited partner units, during the period.

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        EBITDA is a non-GAAP financial measure used as a supplemental financial measure by management and external users of our consolidated financial statements, such as investors, commercial banks and research analysts, to assess:

    our compliance with certain financial covenants included in our debt agreements;

    our financial performance without regard to financing methods, capital structure, income taxes or historical cost basis;

    our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners;

    our operating performance and return on invested capital as compared to those of other companies in the wholesale, marketing and distribution of refined petroleum products, without regard to financing methods and capital structure; and

    the viability of acquisitions and capital expenditure projects and the overall rates of return of alternative investment opportunities.

        EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income, and this measure may vary among other companies. Therefore, EBITDA may not be comparable to similarly titled measures of other companies.

        Distributable cash flow is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on their investment. In December 2009, we amended our partnership agreement to restate the provisions governing conversion of the subordinated units to use distributable cash flow to test whether we have "earned" the minimum quarterly distribution. Distributable cash flow means our net income plus depreciation and amortization minus maintenance capital expenditures, as well as adjustments to eliminate items approved by the audit committee of the board of directors of our general partner that are extraordinary or non-recurring in nature and that would otherwise increase distributable cash flow. Specifically, this financial measure indicates to investors whether or not we have generated sufficient earnings on a current or historic level that can sustain or support an increase in our quarterly cash distribution. Distributable cash flow is a quantitative standard used by the investment community with respect to publicly traded partnerships. Distributable cash flow should not be considered as an alternative to net income, cash flow from operations, or any other measure of financial performance presented in accordance with GAAP. In addition, our distributable cash flow may not be comparable to distributable cash flow or similarly titled measures of other companies.

    Years Ended December 31, 2010, 2009 and 2008

        In September 2010, we acquired 190 Mobil-branded retail gas stations located in Massachusetts, New Hampshire and Rhode Island. Additionally, we acquired the right to supply Mobil-branded gasoline and diesel fuel to such stations and to 31 Mobil-branded stations that are owned and operated by independent dealers. The Acquisition expands our wholesale supply business and adds vertical integration to our transportation fuel business. Please read "Overview—ExxonMobil Acquisition" for a discussion of the transaction.

        In June 2010, we completed our acquisition of the Warex Terminals (three refined petroleum products terminals located in Newburgh, New York). We believe the acquisition strengthens our

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presence along the Hudson River in southeastern New York and enhances terminal operating efficiencies with our neighboring facility.

        In addition, in October 2010, we completed an ethanol and rail expansion project that adds 180,000 barrels of ethanol storage at our refined petroleum product terminal in Albany, New York. The project includes modifications that enable the terminal to schedule the delivery of 80-car trains of ethanol and allows ethanol to be shipped directly on a single rail line from the Midwest. Beyond supplying our own business, we further invested in our Albany terminal by installing a marine vapor recovery system for barge/vessel-loading of ethanol and gasoline at the dock, and expanding the rack to allow for additional ethanol and gasoline sales. We believe the supply efficiencies gained through this project position us to be a premier cost effective supplier of gasoline and ethanol to the Northeast. In a separate and complementary project, we are converting two distillate storage tanks to gasoline storage at the Albany facility. These initiatives, combined with the return to service of three previously out-of-service tanks, increased the total storage capacity of our Albany terminal to approximately 1.2 million barrels, up from 737,000 barrels when we acquired the terminal in May 2007.

        During the year ended December 31, 2010:

    Refined petroleum product prices increased during 2010 compared to 2009.

    Our aggregate volume of product sold increased by approximately 7% for 2010 compared to 2009 primarily due to our gasoline business.

    We expensed credit losses of approximately $1.1 million.

    Temperatures for 2010 were 10% warmer than normal and 11% warmer than 2009.

    We believe heating oil conservation and consumption continued during 2010.

    We believe our results for the fourth quarter 2010 were negatively impacted due, in part, to adverse market conditions and fewer advantageous purchasing opportunities primarily in our distillates business. Although these factors continue to affect our business at the present time, we do not believe they are of a long-term nature. We believe that these market conditions and fewer purchasing opportunities did not adversely impact the performance of our gasoline business including the recent acquisition of retail gas stations and supply rights from ExxonMobil.

        During 2009, we optimized our terminal network by initiating organic expansion and other projects, primarily in Albany, New York, Oyster Bay, New York and Linden, New Jersey. These projects added approximately 1.3 million barrels of storage capacity, broadening the depth and breadth of our strategic asset base.

        During the year ended December 31, 2009:

    Refined petroleum product prices dramatically declined during the first three quarters of 2009 compared to the same periods in 2008 which we believe contributed to lower revenues and lower financing costs as a result of decreased borrowings to finance inventory.

    Refined petroleum product prices, however, dramatically increased during the fourth quarter of 2009 compared to the fourth quarter of 2008.

    Due to the decline in refined petroleum product prices for most of 2009 and due to favorable market conditions, we elected to use our storage capacity to carry increased inventories of $225.6 million as of December 31, 2009 compared December 31, 2008.

    Temperatures for 2009 were 1% colder than normal and 4% colder than 2008 while temperatures were 4% warmer than normal for 2008.

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    We expensed credit losses of approximately $2.2 million.

    We believe heating oil conservation continued during 2009 even though prices declined.

    We believe the overall economic conditions affected our distillates and gasoline results.

    We continued to experience a decline in our residual oil sales and volumes.

        In 2008, we expanded our presence in Providence, Rhode Island. We entered into two separate sublease agreements in November 2007 for land located at the Port of Providence. In January 2008, the terminal at one parcel opened for business and has storage capacity of 244,000 barrels for distillates. In November 2008, the terminal at the other parcel opened for business and has storage capacity of 230,000 barrels for refined petroleum products. These facilities will enable us to more effectively supply existing wholesale and commercial customers across Rhode Island and southeastern Massachusetts and cultivate new customers in the region.

        In 2008, we experienced higher revenues and higher gasoline sales volumes, primarily due to our 2007 acquisitions of five refined petroleum products terminals from ExxonMobil. Refined petroleum product and natural gas prices were higher during the first nine months of the year and generally peaked in July of 2008 before dramatically decreasing during the fourth quarter as evidenced in the table below.

        During the year ended December 31, 2008:

    We believe increasing refined petroleum product prices for most of 2008 contributed to:

    higher financing costs as a result of increased borrowings to finance inventory;

    the conversion or temporary switching by dual-fuel users by primarily commercial customers to other products (primarily natural gas) from residual fuel and heating oil; and

    energy conservation.

    A decrease in market demand for distillates and residual oil due to energy conservation and higher refined petroleum product prices for most of 2008 led to lower volumes sold and lower margins.

    Adverse market conditions in our markets, including volatility and backwardation, led to lower margins and intensified competition from other wholesalers.

    Temperatures were 4% warmer than normal for 2008 as measured by aggregate heating degree days.

    We expensed credit losses of approximately $660,000.

    We had fewer fixed priced sales of heating oil in 2008.

    During the first quarter of 2008, the opportunistic conversion of certain gasoline markets to ethanol put us in a temporarily disadvantaged competitive position while our terminal infrastructure was being converted.

    Temporary logistical supply issues related to rail capacity adversely affected the performance of our Burlington, Vermont facility.

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        The following table provides the percentage increases (decreases) in refined petroleum product and natural gas prices at the end of each quarter in 2010 as compared to each comparable quarter in 2009 and at the end of each quarter in 2009 as compared to each comparable quarter in 2008:

Period:
  Heating Oil
$ per gallon(1)
  Gasoline
$ per gallon(1)
  Residual Oil
$ per gallon(2)
  Natural Gas
$ per gallon
equivalent(3)
 

2010 compared to 2009

                         
 

At March 31, 2009

  $ 1.34   $ 1.40   $ 0.95   $ 0.62  
 

At March 31, 2010

  $ 2.16   $ 2.31   $ 1.76   $ 0.63  
 

Change

    61%     65%     85%     2%  
                   
 

At June 30, 2009

  $ 1.72   $ 1.90   $ 1.49   $ 0.62  
 

At June 30, 2010

  $ 1.98   $ 2.06   $ 1.61   $ 0.75  
 

Change

    15%     8%     8%     21%  
                   
 

At September 30, 2009

  $ 1.80   $ 1.73   $ 1.50   $ 0.54  
 

At September 30, 2010

  $ 2.24   $ 2.04   $ 1.74   $ 0.62  
 

Change

    24%     18%     16%     15%  
                   
 

At December 31, 2009

  $ 2.12   $ 2.05   $ 1.71   $ 1.07  
 

At December 31, 2010

  $ 2.54   $ 2.45   $ 1.86   $ 0.76  
 

Change

    20%     19%     9%     (29%)  
                   

2009 compared to 2008

                         
 

At March 31, 2008

  $ 3.05   $ 2.62   $ 1.73   $ 1.53  
 

At March 31, 2009

  $ 1.34   $ 1.40   $ 0.95   $ 0.62  
 

Change

    (56%)     (47%)     (45%)     (59%)  
                   
 

At June 30, 2008

  $ 3.90   $ 3.50   $ 2.65   $ 2.06  
 

At June 30, 2009

  $ 1.72   $ 1.90   $ 1.49   $ 0.62  
 

Change

    (56%)     (46%)     (44%)     (70%)  
                   
 

At September 30, 2008

  $ 2.86   $ 2.48   $ 1.99   $ 1.13  
 

At September 30, 2009

  $ 1.80   $ 1.73   $ 1.50   $ 0.54  
 

Change

    (37%)     (30%)     (25%)     (52%)  
                   
 

At December 31, 2008

  $ 1.41   $ 1.01   $ 0.85   $ 1.13  
 

At December 31, 2009

  $ 2.12   $ 2.05   $ 1.71   $ 1.07  
 

Change

    50%     103%     101%     (5%)  
                   

(1)
Source: New York Mercantile Exchange (closing price)

(2)
Source: Platts Oilgram Price Report (6-1% New York Harbor; average)

(3)
Source: Platts Gas Daily Report (Tennessee zone delivered)

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    Key Performance Indicators

        The following table provides a summary of some of the key performance indicators that may be used to assess our results of operations. These comparisons are not necessarily indicative of future results (gallons and dollars in thousands, except per unit data):

 
  Years Ended December 31,  
 
  2010   2009   2008  

Net income

  $ 27,038   $ 34,134   $ 21,055  

Net income per diluted limited partner unit(1)

  $ 1.59   $ 2.51   $ 1.57  

EBITDA(2)

  $ 72,437   $ 66,660   $ 58,132  

Distributable cash flow(3)

  $ 46,035   $ 45,433   $ 34,061  

Wholesale Segment:

                   
 

Volume (gallons)

    3,377,351     3,177,574     3,348,238  
 

Sales

                   
   

Gasoline

  $ 4,554,046   $ 2,954,461   $ 4,469,783  
   

Distillates

    2,680,729     2,467,883     4,044,039  
   

Residual oil

    39,353     32,803     75,358  
               
     

Total

  $ 7,274,128   $ 5,455,147   $ 8,589,180  
 

Net product margin(4)

                   
   

Gasoline

  $ 64,677   $ 40,706   $ 36,451  
   

Distillates

    80,948     95,098     70,045  
   

Residual oil

    9,398     9,430     11,671  
               
     

Total

  $ 155,023   $ 145,234   $ 118,167  

Commercial Segment:

                   
 

Volume (gallons)

    273,090     226,193     202,088  
 

Sales

  $ 511,326   $ 363,264   $ 429,943  
               
 

Net product margin(4)

  $ 18,438   $ 15,410   $ 11,835  

All Other:

                   
 

Sales

  $ 16,105   $   $  
               
 

Net product margin(4)

  $ 8,885   $   $  

Combined sales and net product margin:

                   
 

Sales

  $ 7,801,559   $ 5,818,411   $ 9,019,123  
               
 

Net product margin(4)

  $ 182,346   $ 160,644   $ 130,002  
 

Depreciation allocated to cost of sales

    15,628     10,816     10,211  
               

Combined gross profit

  $ 166,718   $ 149,828   $ 119,791  
               

Weather conditions:

                   

Normal heating degree days

    5,630     5,630     5,630  

Actual heating degree days

    5,049     5,656     5,426  

Variance from normal heating degree days

    (10)%     1%     (4)%  

Variance from prior period actual heating degree days

    (11)%     4%     (4)%  

(1)
See Note 2 of Notes to Consolidated Financial Statements for net income per diluted limited partner unit calculation.

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(2)
EBITDA is a non-GAAP financial measure which is discussed above under "—Evaluating Our Results of Operations." The table below presents reconciliations of EBITDA to the most directly comparable GAAP financial measures.

(3)
Distributable cash flow is a non-GAAP financial measure which is discussed above under "—Evaluating Our Results of Operations." The table below presents reconciliations of distributable cash flow to the most directly comparable GAAP financial measures.

(4)
Net product margin is a non-GAAP financial measure which is discussed above under "—Evaluating Our Results of Operations." The table above reconciles net product margin on a combined basis to gross profit, a directly comparable GAAP financial measure.

        The following table presents reconciliations of EBITDA to the most directly comparable GAAP financial measures on a historical basis (in thousands):

 
  Years Ended December 31,  
 
  2010   2009   2008  

Reconciliation of net income to EBITDA:

                   
 

Net income

  $ 27,038   $ 34,134   $ 21,055  
 

Depreciation and amortization and amortization of deferred financing fees

    23,089     15,909     15,126  
 

Interest expense

    22,310     15,188     20,799  
 

Income tax expense

        1,429     1,152  
               
 

EBITDA

  $ 72,437   $ 66,660   $ 58,132  
               

Reconciliation of net cash (used in) provided by operating activities to EBITDA:

                   
 

Net cash (used in) provided by operating activities

  $ (87,194 ) $ (61,129 ) $ 99,220  
 

Net changes in operating assets and liabilities and certain non-cash items

    137,321     111,172     (63,039 )
 

Interest expense

    22,310     15,188     20,799  
 

Income tax expense

        1,429     1,152  
               
 

EBITDA

  $ 72,437   $ 66,660   $ 58,132  
               

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        The following table presents reconciliations of distributable cash flow to the most directly comparable GAAP financial measures on a historical basis (in thousands):

 
  Years Ended December 31,  
 
  2010   2009   2008  

Reconciliation of net income to distributable cash flow:

                   
 

Net income

  $ 27,038   $ 34,134   $ 21,055  
 

Depreciation and amortization and amortization of deferred financing fees

    23,089     15,909     15,126  
 

Maintenance capital expenditures

    (4,092 )   (4,610 )   (2,120 )
               
 

Distributable cash flow

  $ 46,035   $ 45,433   $ 34,061  
               

Reconciliation of net cash (used in) provided by operating activities to distributable cash flow:

                   
 

Net cash (used in) provided by operating activities

  $ (87,194 ) $ (61,129 ) $ 99,220  
 

Net changes in operating assets and liabilities and certain non-cash items

    137,321     111,172     (63,039 )
 

Maintenance capital expenditures

    (4,092 )   (4,610 )   (2,120 )
               
 

Distributable cash flow

  $ 46,035   $ 45,433   $ 34,061  
               

        Our total sales for 2010 increased by $1,983.1 million, or 34%, to $7,801.5 million compared to $5,818.4 million for 2009. The increase was driven primarily by higher refined petroleum product and natural gas prices for 2010 compared to 2009. Our aggregate volume of product sold increased by approximately 246 million gallons, or 7%, to 3,650 million gallons. The increase in volume primarily includes an increase of approximately 424 million gallons in gasoline due, in part, to our acquisitions in June 2010 of the Warex Terminals and in September 2010 of retail gas stations and supply rights from ExxonMobil. The increase in volume sold was offset by a decrease of 195 million gallons in distillates attributable to warmer temperatures during 2010 compared to 2009, increased competition in the marketplace, continued conservation, economic conditions and fewer advantageous purchasing opportunities. The number of actual heating degree days decreased 11% to 5,049 for 2010 compared to 5,656 for 2009. Our gross profit for 2010 was $166.7 million, an increase of $16.9 million, or 11%, compared to $149.8 million for 2009, due primarily to strong unit margins for gasoline offset by lower unit margins in distillate products.

        Our total sales for 2009 decreased by $3,200.7 million, or 35%, to $5,818.4 million compared to $9,019.1 million for 2008. The decrease was driven primarily by significantly lower refined petroleum product and natural gas prices for most of 2009 compared to 2008. Our aggregate volume of product sold decreased by approximately 146 million gallons, or 4%, to 3,404 million gallons. The decrease in volume primarily includes decreases of approximately 84 million gallons, 63 million gallons and 11 million gallons in gasoline, distillates and residual oil, respectively, mostly attributed to continued conservation, increased competition in the marketplace and economic conditions, despite colder temperatures. Our gross profit for 2009 was $149.8 million, an increase of $30.0 million, or 25%, compared to $119.8 million for 2008. The increase was primarily due to higher net product margins in distillates and gasoline.

        Gasoline. Wholesale gasoline sales for 2010 were $4,554.0 million compared to $2,954.5 million for 2009. The increase of $1,599.5 million, or 54%, was due primarily to our acquisitions in June 2010 of the Warex Terminals and in September 2010 of retail gas stations and supply rights from ExxonMobil,

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as well as to higher gasoline prices and an increase in gasoline volume sold compared to 2009. The increase in gasoline volume was primarily due to our 2010 acquisitions. Our net product margin from gasoline sales increased by $24.0 million to $64.7 million for 2010 compared to $40.7 million for 2009. This increase was primarily attributable to improved unit margins and the increase in gasoline volume sold for 2010 compared to 2009.

        Wholesale gasoline sales for 2009 were $2,954.5 million compared to $4,469.8 million for 2008. The decrease of $1,515.3 million, or 34%, was due primarily to significantly lower gasoline prices for most of 2009 compared to 2008 and an 84 million gallon decrease in volume sold attributed to continued conservation, increased competition in the marketplace and economic conditions. Our net product margin from gasoline sales increased by $4.2 million to $40.7 million for 2009 compared to $36.5 million for 2008, primarily attributable to advantageous purchasing opportunities and improved unit margins through diligent inventory and sales management.

        Distillates. Wholesale distillate sales for 2010 were $2,680.7 million compared to $2,467.8 million for 2009. The increase of $212.9 million, or 9%, was primarily due to increased refined petroleum product prices. We experienced a 14% decrease in volume sold for 2010 compared to 2009 due to warmer temperatures, increased competition in the marketplace, continued conservation and economic conditions. Primarily for the same reasons as well as to fewer advantageous purchasing opportunities, our net product margin from distillate sales decreased by 15% to $80.9 million for 2010 compared to $95.1 million for 2009.

        Wholesale distillate sales for 2009 were $2,467.8 million compared to $4,044.0 million for 2008. The decrease of $1,576.2 million, or 39%, was due to the significantly lower refined petroleum product prices for most of 2009. We experienced a 73 million gallon decrease in distillate volume sold for 2009 compared to 2008 which was attributed to continued conservation, increased competition in the marketplace and economic conditions. Our net product margin from distillate sales increased by $25.1 million, or 36%, to $95.1 million 2009 compared to $70.0 million for 2008, primarily attributable to advantageous purchasing opportunities and improved unit margins through diligent inventory and sales management.

        Residual Oil. Wholesale residual oil sales for 2010 were $39.4 million compared to $32.8 million for 2009. The increase of $6.6 million, or 20%, was primarily due to the increase in refined petroleum product prices compared to 2009. We experienced a 15% decrease year over year in residual oil volume sold, primarily due to warmer temperatures, continued conservation, challenging economic conditions, system conversions and fuel switching due to the comparative price advantage of natural gas over residual oil. Our net product margin contributions from residual oil sales was flat at $9.4 million for 2010 and 2009.

        Wholesale residual oil sales for 2009 were $32.8 million compared to $75.4 million for 2008. The decrease of $42.6 million, or 56%, was primarily due to significantly lower refined petroleum product prices for most of 2009 compared to 2008 and a decrease in volume sold. The decrease in volume sold was the result of continued conservation, economic conditions and conversion and fuel switching related to the decrease in natural gas prices compared to residual oil prices. Our net product margin contribution from residual oil sales decreased by $2.2 million, or 19%, to $9.4 million for 2009 compared to $11.7 million for 2008 due to a decrease in volume sold and intensified competition in the marketplace.

        In our Commercial segment, residual oil accounted for approximately 51%, 61% and 67% of total commercial volume sold in 2010, 2009 and 2008, respectively. Distillates, gasoline and natural gas accounted for the remainder of the total volume sold. Commercial residual oil sales increased by approximately 22% due to increased refined petroleum product prices for 2010 compared to 2009. We

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attribute the decrease in volume sold to the competitive pricing from natural gas and reductions in production by certain industry participants in our markets.

        Commercial residual oil sales and volume sold for 2009 decreased by 21% and 2%, respectively, compared to 2008. We attribute the decreases in sales and volume sold to the competitive pricing from natural gas and reductions in production by certain industry participants in our markets.

    All Other Segment

        This segment consists primarily of convenience stores sales at our directly operated stores and gas station rental income which generated approximately $16.1 million, or 0.21%, of our total sales for the year ended December 31, 2010.

        SG&A expenses increased by $5.1 million, or 8%, to $66.1 million for 2010 compared to $61.0 million for 2009. The increase was primarily due to increases of $5.0 million in overhead (including information technology, natural gas personnel and project management), $3.0 million in bank fees and amortization of deferred financing fees largely related to the expansions of our bank facilities, $0.8 million in management fees to Alliance, $0.6 million in costs associated with the expansion of our natural gas operations and $0.3 million in various other SG&A expenses. The increase in SG&A expenses also included one-time increases of $1.4 million in legal, consulting and other expenses related to the FTC's regulatory review of our acquisition of the Warex Terminals and $0.8 million of one-time acquisition costs associated with the September 2010 acquisition of retail gas stations and supply rights from ExxonMobil. The increase in SG&A expenses was offset by decreases of $5.8 million in incentive compensation and $1.1 million in bad debt accruals.

        SG&A expenses for 2009 increased by approximately $18.9 million to $61.0 million compared to $42.1 million for 2008. We had increases in variable SG&A expenses of approximately $7.7 million in bonuses and $1.9 million in bad debt accruals and credit collections. Increases in other variable SG&A expense for 2009 included $3.6 million in project development and due diligence costs which are generally one-time in nature. Included in the $3.6 million are some enhancements we made in our information technology infrastructure, including implementing an enterprise-wide system that provides improved access to information about hedging activities, inventory, scheduling, pricing and sales activities.

        The increase in SG&A expenses in 2009 was also due to increases of approximately $1.2 million in compensation costs on our long-term incentive plan, $0.9 million in salaries, $0.9 million in costs associated with the expansion of our natural gas operations, $0.6 million in professional and consulting fees, $0.5 million in bank fees, $0.4 million in building and computer rent expenses, $0.4 million in franchise taxes and $2.4 million in various other SG&A expenses. The increase in SG&A expenses was offset by a $1.5 million curtailment gain associated with the pension plan freeze.

        Operating expenses increased by $12.8 million, or 36%, to $47.8 million for 2010 compared to $35.0 million for 2009. The increase was primarily due to $8.3 million in expenses related to the retail gas stations acquired from ExxonMobil, $2.4 million in expenses related to the Warex Terminals and $2.0 million in various other operating expenses.

        Operating expenses were $35.0 million for 2009 compared to $31.8 million for 2008. Operating expenses for 2008, however, included an offset of $2.8 million due to a change in estimate of our remediation obligations under a proposed remedial action work plan submitted by us to NYDEC related to our Albany, New York terminal. If not for the $2.8 million offset, operating expenses for

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2008 would have been approximately $34.6 million. The increase in 2009 operating expenses was primarily due to increased costs of approximately $1.7 million related to our leased storage facility in Oyster Bay (Commander) New York, offset by decreases of $1.0 million in cost savings related to the non-renewal of the terminal lease in New Haven, Connecticut and $0.3 million in other operating expenses.

        Amortization expense related to our intangible assets was $3.5 million, $3.0 million and $2.9 million for 2010, 2009 and 2008, respectively. The increase of $0.5 million in 2010 compared to 2009 was primarily the result of amortization related to intangible assets recognized as part of the 2010 acquisitions.

        Interest expense for 2010 increased by $7.1 million, or 47%, to $22.3 million compared to $15.2 million for 2009. The increase was primarily attributable to higher average balances on our working capital revolving credit facility from carrying higher average balances of inventories and accounts receivable reflecting increased refined petroleum product prices. Also, we had additional borrowing costs as a result of the acquisitions of the Warex Terminals and the retail gas stations and supply rights from ExxonMobil. In addition, the costs of borrowings under our credit agreement were increased in connection with the May 14, 2010 and August 18, 2010 amendments to the credit agreement.

        Interest expense for 2009 decreased by $5.6 million, or 27%, to $15.2 million compared to $20.8 million for 2008. We attribute the decrease primarily to lower average costs on our working capital revolving credit facility from carrying lower average balances on inventories and accounts receivable due to lower refined petroleum product prices for most of 2009. In addition, interest rates were lower during the 2009 compared to 2008.

Liquidity and Capital Resources

        Our primary liquidity needs are to fund our working capital requirements, capital expenditures and distributions. Cash generated from operations and our working capital revolving credit facility provide our primary sources of liquidity. Working capital increased by $150.7 million to $445.9 million at December 31, 2010 compared to $295.2 million at December 31, 2009 primarily as a result of the public offerings discussed below.

        On February 12, 2010, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $6.5 million for the fourth quarter of 2009. On May 14, 2010, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $8.5 million for the first quarter of 2010. On August 13, 2010, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $8.5 million for the second quarter of 2010. On November 12, 2010, we paid a cash distribution to our common and subordinated unitholders and our general partner of approximately $8.6 million for the third quarter of 2010.

        On March 19, 2010, we completed a public offering of 3,910,000 common units at a price of $22.75 per common unit. Net proceeds were approximately $84.6 million, after deducting approximately $4.4 million in underwriting fees and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our credit agreement.

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        On June 30, 2010, we completed our acquisition of the Warex Terminals for cash consideration of approximately $46.0 million plus the assumption of certain environmental liabilities.

        On September 30, 2010, we completed our acquisition of retail gas stations and supply rights from ExxonMobil for cash consideration of approximately $202.3 million plus the assumption of certain environmental liabilities.

        On November 16, 2010, we completed a public offering of 1,955,000 common units at a price of $25.57 per common unit. Net proceeds were approximately $47.7 million, after deducting approximately $2.3 million in underwriting fees and offering expenses.

        We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations at December 31, 2010 are as follows (in thousands):

 
  Payments due by period  
 
  Total   Less than
1 year
  1-3 years   4-5 years   More than
5 years
 

Revolver loan obligations(1)

  $ 832,600   $ 200,420   $ 537,156   $ 95,024   $  

Operating lease obligations(2)

    70,970     17,285     28,742     8,089     16,854  

Capital lease obligations

    884     280     230     132     242  

Other long-term liabilities(3)

    300,505     32,847     66,112     66,344     135,202  
                       
 

Total

  $ 1,204,959   $ 250,832   $ 632,240   $ 169,589   $ 152,298  
                       

(1)
Includes principal and interest on our working capital revolving credit facility at December 31, 2010 and assumes a ratable payment through the expiration date. The credit agreement has a contractual maturity of May 14, 2014 and no principal payments are required prior to that date. However, we repay amounts outstanding and reborrow funds based on our working capital requirements. Therefore, the current portion of the working capital revolving credit facility included in the accompanying balance sheets is the amount we expect to pay down during the course of the year, and the long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year.

(2)
Includes operating lease obligations with related parties and gas station leases.

(3)
Includes amounts related to the 15-year BFA. Please read "—ExxonMobil Acquisition—Brand Fee Agreement" and minimum freight requirements on the transportation of ethanol to our Albany, New York terminal.

        In addition to the obligations described in the above table, we have minimum volume purchase requirements at December 31, 2010. Pricing is based on spot prices at the time of purchase. Please read Note 13, Commitments and Contingencies, of Notes to Consolidated Financial Statements with respect to purchase commitments and sublease information related to certain lease agreements.

        Our operations require investments to expand, upgrade and enhance existing operations, and to meet environmental and operations regulations. We categorize our capital requirements as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to repair or replace partially or fully depreciated assets to maintain the operating capacity of, or revenues generated by, existing assets and extend their useful lives. Maintenance capital expenditures include expenditures required to maintain equipment reliability, tankage and pipeline integrity and safety and to address certain environmental regulations. We

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anticipate that maintenance capital expenditures will be funded with cash generated by operations. We had approximately $4.1 million, $4.6 million and $2.1 million in maintenance capital expenditures for the years ended December 31, 2010, 2009 and 2008, respectively, which are included in capital expenditures in the accompanying consolidated statements of cash flows. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

        Expansion capital expenditures include expenditures to acquire assets to grow our business or expand our existing facilities, such as projects that increase our operating capacity or revenues by increasing tankage, diversifying product availability at various terminals and adding terminals. We have the ability to fund our expansion capital expenditures through cash from operations or our credit agreement or by issuing additional equity. We had approximately $258.9 million, $4.5 million and $9.4 million in expansion capital expenditures for the years ended December 31, 2010, 2009 and 2008, respectively. Specifically, for 2010, expansion capital expenditures included approximately $248.3 million in acquisitions including $202.3 million for the purchase of retail gas stations and supply rights from ExxonMobil and $46.0 million in terminal acquisition costs related to the acquisition of the Warex Terminals. In addition, we had $10.6 million in expansion capital expenditures which consisted of $7.7 million in expenditures related to our Albany, New York terminal, $1.8 million in terminal and computer equipment at the Warex Terminals, $0.5 million in bio-fuel conversion costs at our Chelsea, Massachusetts terminal and $0.6 million in other expansion capital expenditures, which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $7.7 million in expenditures related to our Albany terminal include costs related to our terminal and rail ethanol expansion project, a continuing program to bring previously out-of-permit tanks back online, the installation of a marine vapor recovery system to allow for barge/vessel loading of gasoline and ethanol and the continuing effort to convert two distillate storage tanks to gasoline.

        In 2009, expansion capital expenditures included approximately $3.2 million at the Albany, New York terminal in costs related to bringing formerly out-of-permit tanks back online and to dock expansion, $0.9 million in additional terminal equipment at the Providence, Rhode Island terminal, $0.2 million in automation costs at our leased storage facility in Long Island, New York and $0.2 million in other expansion capital expenditures.

        In 2008, expansion capital expenditures included approximately $6.4 million in costs primarily related to the second phase of construction of our terminal in Providence, Rhode Island, $1.2 million related to conversion expenditures to handle ethanol-based gasoline and $1.8 million in other expansion capital expenditures primarily related to additional terminal equipment at the Albany and Newburgh, New York and Burlington, Vermont terminals.

        We believe that we will have sufficient cash flow from operations, borrowing capacity under our credit agreement and the ability to issue additional common units and/or debt securities to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity as well as our ability to issue additional common units and/or debt securities.

 
  Years Ended December 31,  
 
  2010   2009   2008  

Net cash (used in) provided by operating activities

  $ (87,194 ) $ (61,129 ) $ 99,220  

Net cash used in investing activities

  $ (262,997 ) $ (9,062 ) $ (11,510 )

Net cash provided by (used in) financing activities

  $ 351,890   $ 69,908   $ (88,875 )

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        Cash flow from operating activities generally reflects our net income, depreciation and amortization levels, as well as balance sheet changes arising from inventory purchasing patterns, the timing of collections on our accounts receivable, the seasonality of our business, fluctuations in refined petroleum product prices, our working capital requirements and general market conditions.

        Net cash used in operating activities was $87.2 million for the year ended December 31, 2010 compared to $61.2 million for year ended December 31, 2009, for a year-over-year increase in cash used in operating activities of $26.1 million.

        During the year ended December 31, 2010, we experienced increases in refined petroleum products prices, and we funded additional working capital requirements due to our acquisitions of the Warex Terminals and retail gas stations and supply rights from ExxonMobil. As a result, for the year ended December 31, 2010 compared to the year ended December 31, 2009, we had increases of $217.1 million in accounts receivable, $120.9 million in inventories and $200.0 million in accounts payable. Net cash used in operating activities was offset by $27.0 million in net income.

        In addition, through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to our inventories. Specifically, in 2010, the contracts supporting our forward fixed price hedge program required margin payments of $10.8 million to the NYMEX due to market direction, while similar hedging activity in 2009 provided funds from the NYMEX of $171.9 million.

        Net cash used in operating activities was $61.1 million for the year ended December 31, 2009 compared to net cash provided by operating activities of $99.2 million for year ended December 31, 2008, for a year-over-year decrease in cash from operating activities of $160.3 million.

        During the first three quarters of 2009, refined petroleum product and natural gas prices declined significantly compared to same periods in 2008, while refined petroleum product prices rose significantly during the fourth quarter of 2009 compared to the fourth quarter of 2008. Due to favorable market conditions, we elected to use our storage capacity to carry increased inventories. As a result of these factors, for the year ended December 31, 2009 compared to the year ended December 31, 2008, we had increases of approximately $225.6 million in inventories, $89.3 million in accounts receivable and $47.2 million in accounts payable and accrued expenses and other current liabilities. Through the use of regulated exchanges or derivatives, we maintain a position that is substantially hedged with respect to such inventories. The cash used in operating activities was offset by $34.1 million in net income and a $171.9 million change in the fair value of our forward fixed price contracts. For the year ended December 31, 2009, contracts supporting our forward fixed price hedge program provided these funds from the NYMEX due to market direction.

        During 2008, refined petroleum product prices were higher for most of the year and declined significantly during the fourth quarter, thereby causing the carrying values of our accounts receivable, inventories and accounts payable at December 31, 2008 to be less than the carrying values we experienced at the beginning of the year.

        The increase in cash provided by operating activities for 2008 also included net income of $21.1 million and a $195.0 million change in the fair value of our forward fixed price contracts and other derivatives. For 2008, contracts supporting our forward fixed price hedge program required these margin payments to the NYMEX.

        Net cash used in investing activities was $263.0 million for 2010 compared to $9.1 million for 2009, and included $4.1 million in maintenance capital expenditures and $258.9 million in expansion capital expenditures. The $258.9 million included approximately $248.3 million in acquisitions including $202.3 million for the purchase of retail gas stations and supply rights from ExxonMobil and $46.0 million in terminal acquisition costs related to the acquisition of the Warex Terminals. In addition, we had $10.6 million in expansion capital expenditures which consisted of $7.7 million in

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expenditures related to our Albany, New York terminal, $1.8 million in terminal and computer equipment at the Warex Terminals, $0.5 million in bio-fuel conversion costs at our Chelsea, Massachusetts terminal and $0.6 million in other expansion capital expenditures, which are included in capital expenditures in the accompanying consolidated statements of cash flows. The $7.7 million in expenditures related to our Albany terminal include costs related to our terminal and rail ethanol expansion project, a continuing program to bring previously out-of-permit tanks back online, the installation of a marine vapor recovery system to allow for barge/vessel loading of gasoline and ethanol and the continuing effort to convert two distillate storage tanks to gasoline.

        Net cash used in investing activities was $9.1 million for 2009 and included $4.6 million in maintenance capital expenditures and $4.5 million in expansion capital expenditures ($3.2 million at the Albany, New York terminal in costs related to bringing formerly out-of-permit tanks back online and to dock expansion, $0.9 million in additional terminal equipment at the Providence, Rhode Island terminal, $0.2 million in automation costs at our recently leased storage facility in Long Island, New York and $0.2 million in other expansion capital expenditures).

        Net cash used in investing activities for 2008 included $11.5 million in total capital expenditures comprised of $2.1 million in maintenance capital expenditures and $9.4 million in expansion capital expenditures ($6.4 million related to construction in process on our leased terminal in Providence, Rhode Island, $1.2 million related to conversion expenditures to handle ethanol-based gasoline and $1.8 million in other expansion capital expenditures).

        Net cash provided by financing activities was $351.9 million for 2010 and included net borrowings on our credit facilities of $252.9 million and $132.2 million in net proceeds from our public offerings of common units, offset by $31.9 million in cash distributions to our common and subordinated unitholders and our general partner, $0.9 million in the repurchases of common units pursuant to our repurchase program for future satisfaction of our general partner's obligations and $0.4 million in repurchased units held for tax obligations related to units distributed under the LTIP. The general partner's obligations include anticipated obligations to deliver common units under the LTIP and meeting the general partner's obligations under existing employment agreements and other employment related obligations of the general partner.

        Net cash provided by financing activities was $69.9 million for 2009 and primarily included $100.3 million in net proceeds from our credit facilities, offset by $26.1 million in cash distributions to our common and subordinated unitholders and our general partner, $4.0 million in the repurchases of common units pursuant to our repurchase program for future satisfaction of our general partner's obligations and $0.3 million in repurchased units held for tax obligations related to units distributed under the LTIP.

        Net cash used in financing activities was $88.9 million for 2008 and included $61.5 million in net payments on our credit facilities, $26.1 million in cash distributions to our common and subordinated unitholders and our general partner, and $1.2 million in payments on our note payable.

        On August 18, 2010, we, our general partner, our operating company and our operating subsidiaries amended our credit agreement. In accordance with the credit agreement and in connection with the acquisition of retail gas stations and supply rights from ExxonMobil, we requested, and certain lenders under the credit agreement agreed to, an increase in the revolving credit facility in an amount equal to $200.0 million for a total credit facility of up to $1.15 billion. We repay amounts outstanding and reborrow funds based on our working capital requirements and, therefore, classify as a current liability the portion of the working capital revolving credit facility we expect to pay down during the course of the year. The long-term portion of the working capital revolving credit facility is the amount we expect to be outstanding during the entire year. The credit agreement will mature on May 14, 2014.

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        There are two facilities under our credit agreement:

    a working capital revolving credit facility to be used for working capital purposes and letters of credit in the principal amount equal to the lesser of our borrowing base and $800.0 million; and

    a $350.0 million revolving credit facility to be used for acquisitions and general corporate purposes.

        In addition, the credit agreement has an accordion feature whereby we may request on the same terms and conditions of our then existing credit agreement, provided no Event of Default (as defined in the credit agreement) then exists, an increase to the revolving credit facility, the working capital revolving credit facility, or both, by up to another $200.0 million, for a total credit facility of up to $1.35 billion. Any such request for an increase by us must be in a minimum amount of $5.0 million, and the revolving credit facility may not be increased by more than $50.0 million. We cannot provide assurance, however, that our lending group will agree to fund any request by us for additional amounts in excess of the total available commitments of $1.15 billion.

        Availability under our working capital revolving credit facility is subject to a borrowing base which is redetermined from time to time and based on specific advance rates on eligible current assets. Under the credit agreement, our borrowings under the working capital revolving credit facility cannot exceed the then current borrowing base. Availability under our borrowing base may be affected by events beyond our control, such as changes in refined petroleum product prices, collection cycles, counterparty performance, advance rates and limits and general economic conditions. These and other events could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We can provide no assurance that such waivers, amendments or alternative financing could be obtained, or, if obtained, would be on terms acceptable to us.

        During the period from January 1, 2009 through May 13, 2010, borrowings under the working capital revolving credit facility bore interest at (1) the Eurodollar rate plus 1.75% to 2.25%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the previous credit agreement, which in turn depended upon the Combined Interest Coverage Ratio (as defined in the previous credit agreement). Borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 2.25% to 2.75%, (2) the cost of funds rate plus 1.75% to 2.25%, or (3) the base rate plus 0.75% to 1.25%, each depending on the pricing level provided in the previous credit agreement, which in turn depended upon the Combined Interest Coverage Ratio under the previous credit agreement.

        Commencing May 14, 2010, borrowings under the working capital revolving credit facility bear interest at (1) the Eurodollar rate plus 2.50% to 3.00%, (2) the cost of funds rate plus 2.50% to 3.00%, or (3) the base rate plus 1.50% to 2.00%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Utilization Amount (as defined in the credit agreement).

        During the period from May 14, 2010 through September 7, 2010, borrowings under the revolving credit facility bore interest at (1) the Eurodollar rate plus 3.00% to 3.25%, (2) the cost of funds rate plus 3.00% to 3.25%, or (3) the base rate plus 2.00% to 2.25%, each depending on the pricing level provided in the credit agreement, which in turn depended upon the Combined Senior Secured Leverage Ratio (as defined in the credit agreement).

        Commencing September 8, 2010, borrowings under the revolving credit facility bear interest at (1) the Eurodollar rate plus 3.00% to 3.875%, (2) the cost of funds rate plus 3.00% to 3.875%, or (3) the base rate plus 2.00% to 2.875%, each depending on the pricing level provided in the credit agreement, which in turn depends upon the Combined Total Leverage Ratio (as defined in the credit agreement). The average interest rates for the credit agreement were 3.7%, 3.6% and 4.6% for the years ended December 31, 2010, 2009 and 2008, respectively.

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        We incur a letter of credit fee of 2.50%—3.00% per annum for each letter of credit issued. In addition, we incur a commitment fee on the unused portion of each facility under the credit agreement equal to 0.50% per annum.

        As of December 31, 2010, we had total borrowings outstanding under the credit agreement of $786.7 million, including $300.0 million outstanding on our revolving credit facility. In addition, we had outstanding letters of credit of $110.7 million. Subject to borrowing base limitations, the total remaining availability for borrowings and letters of credit was $252.6 million and $211.2 million at December 31, 2010 and 2009, respectively.

        The credit agreement imposes financial covenants that require us to maintain certain minimum working capital amounts, capital expenditure limits, a minimum EBITDA, a minimum combined interest coverage ratio, a maximum senior secured leverage ratio and a maximum total leverage ratio. We were in compliance with the foregoing covenants at December 31, 2010. The credit agreement also contains a representation whereby there can be no event or circumstance, either individually or in the aggregate, that has had or could reasonably be expected to have a Material Adverse Effect (as defined in the credit agreement). Under the credit agreement, the clean down requirement of the previous credit agreement was eliminated.

        The credit agreement limits distributions to our unitholders to available cash.

        Our obligations under the credit agreement are secured by substantially all of our assets and the assets of our operating company and operating subsidiaries.

        The lending group under the credit agreement is comprised of the following institutions: Bank of America, N.A.; JPMorgan Chase Bank, N.A.; Wells Fargo Bank, N.A.; Societe Generale; Standard Chartered Bank; RBS Citizens, National Association; BNP Paribas; Cooperative Centrale Raiffeisen-Boerenleenbank B.A., "Rabobank Nederland" New York Branch; Sovereign Bank; Credit Agricole Corporate and Investment Bank; Keybank National Association; Toronto Dominion (New York); RB International Finance (USA) LLC (formerly known as RZB Finance LLC); Royal Bank of Canada; Raymond James Bank, FSB; Barclays Bank plc; Webster Bank, National Association; Natixis, New York Branch; DZ Bank AG Deutsche Zentral-Genossenschaftsbank Frankfurt Am Main; Branch Banking & Trust Company; and Sumitomo Mitsui Banking Corporation.

    Off-Balance Sheet Arrangements

        We have no off-balance sheet arrangements.

Impact of Inflation

        Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2010, 2009 and 2008.

Environmental Matters

        Our business of supplying refined petroleum products involves a number of activities that are subject to extensive and stringent environmental laws. For a complete discussion of the environmental laws and regulations affecting our business, please read Items 1 and 2, "Business and Properties—Environmental."

Critical Accounting Policies and Estimates

        A summary of the significant accounting policies that we have adopted and followed in the preparation of our consolidated financial statements is detailed in Note 2 of Notes to Consolidated Financial Statements. Certain of these accounting policies require the use of estimates. These estimates

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are based on our knowledge and understanding of current conditions and actions that we may take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our financial condition and results of operations and are recorded in the period in which they become known. We have identified the following estimates that, in our opinion, are subjective in nature, require the exercise of judgment and involve complex analysis:

        Except for our convenience store inventory, we hedge substantially all of our inventory purchases through futures contracts and swap agreements. Hedges are executed when inventory is purchased and are identified with that specific inventory. Changes in the fair value of these contracts, as well as the offsetting gain or loss on the hedged inventory item, are recognized in earnings as an increase or decrease in cost of sales. All hedged inventory is valued using the lower of cost, as determined by specific identification, or market. Prior to sale, hedges are removed from specific barrels of inventory, and the then unhedged inventory is sold and accounted for on a first-in, first-out basis. In addition to our own inventory, we have exchange agreements with unrelated third party suppliers, whereby we may draw inventory from these other suppliers and replace it at a later date. Similarly, these suppliers may draw inventory from us and replace it at a later date. Positive exchange balances are accounted for as accounts receivable. Negative exchange balances are accounted for as accounts payable. Exchange transactions are valued using current quoted market prices. In addition, we have convenience store inventory which is carried at the lower of historical cost or market.

        We have a throughput agreement with Global Petroleum Corp., one of our affiliates, with respect to its terminal in Revere, Massachusetts. This agreement is accounted for as an operating lease. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Throughput Agreement with Global Petroleum Corp." We also have entered into terminal and throughput lease arrangements with various unrelated oil terminals, certain of which arrangements have minimum usage requirements. Please read Items 1 and 2, "Business and Properties—Storage." In addition, we lease certain gas stations from third parties under long-term arrangements with various expiration dates.

        We have future commitments, principally for office space and computer equipment, under the terms of operating lease arrangements. We have rental income from gas stations leased to independents dealers and lease income from office space leased to an unrelated third party at one of our terminals. Additionally, we have capital leases for other computer equipment and leasehold improvements. Accounting and reporting guidance for leases requires that leases be evaluated and classified as operating or capital leases for financial reporting purposes. The lease term used for lease evaluation includes option periods only in instances in which the exercise of the option period can be reasonably assured and failure to exercise such options would result in an economic penalty.

        Sales relate primarily to the sale of refined petroleum products and natural gas and are recognized along with the related receivable upon delivery, net of applicable provisions for discounts and allowances. Allowances for cash discounts are recorded as a reduction of sales at the time of sale based on the estimated future outcome. We also provide for shipping costs at the time of sale, which are included in cost of sales. The amounts recorded for bad debts are generally based upon historically derived percentages while also factoring in any new business conditions that might impact the historical analysis, such as market conditions and bankruptcies of particular customers. Bad debt provisions are included in selling, general and administrative expenses. Convenience store products are recognized net

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of applicable provisions for discounts and allowances upon delivery, generally, at the point of sale. Rental income is recognized on a straight-line basis over the term of the lease.

        Revenue is not recognized on exchange agreements, which are entered into primarily to acquire various refined petroleum products of a desired quality or to reduce transportation costs by taking delivery of products closer to our end markets. Any net differential for exchange agreements is recorded as a nonmonetary adjustment of inventory costs in the purchases component of cost of sales in the statement of income.

        Accounting and reporting guidance for derivative instruments and hedging activities requires that an entity recognize derivatives as either assets or liabilities on the balance sheet and measure the instruments at fair value. Changes in the fair value of the derivative are to be recognized currently in earnings, unless specific hedge accounting criteria are met.

        Fair Value Hedges—The fair value of our derivatives is determined through the use of independent markets and is based upon the prevailing market prices of such instruments at the date of valuation. We enter into futures contracts for the receipt or delivery of refined petroleum products in future periods. The contracts are entered into in the normal course of business to reduce risk of loss of inventory on hand, which could result through fluctuations in market prices. Changes in the fair value of these contracts, as well as the offsetting gain or loss on the hedged inventory item, are recognized in earnings as an increase or decrease in cost of sales.

        We also use futures contracts and swap agreements to hedge exposure under forward purchase and sale commitments. These agreements are intended to hedge the cost component of virtually all of our forward purchase and sale commitments. Changes in the fair value of these contracts, as well as offsetting gains or losses on the forward fixed price purchase and sale commitments, are recognized in earnings as an increase or decrease in cost of sales. Gains and losses on net product margin from forward fixed price purchase and sale contracts are reflected in earnings as an increase or decrease in cost of sales as these contracts mature.

        We also market and sell natural gas. We generally conduct business by entering into forward purchase commitments for natural gas only when we simultaneously enter into arrangements for the sale of product for physical delivery to third-party users. We generally take delivery under our purchase commitments at the same location as we deliver to third-party users. Through these transactions, which establish an immediate margin, we seek to maintain a position that is substantially balanced between firm forward purchase and sales commitments. Natural gas is generally purchased and sold at fixed prices and quantities. Current price quotes from actively traded markets are used in all cases to determine the contracts' fair value. Changes in the fair value of these contracts are recognized in earnings as an increase or decrease in cost of sales.

        Interest Rate Hedges—We link all hedges that are designated as cash flow hedges to forecasted transactions. To the extent such hedges are effective, the changes in the fair value of the derivative instrument are reported as a component of other comprehensive income and reclassified into interest expense in the same period during which the hedged transaction affects earnings. We executed two zero premium interest rate collars with major financial institutions. Each collar is designated as a cash flow hedge. The first collar, which expires on May 14, 2011, is used to hedge the variability in interest payments due to changes in the three-month LIBOR rate with respect to $100.0 million of three-month LIBOR-based borrowings. Under the first collar, we capped our exposure at a maximum three-month LIBOR rate of 5.75% and established a minimum floor rate of 3.75%. The changes in the fair value of the first collar are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the three-month LIBOR rate above and below the first collar's strike rates. The second collar, which expires on October 2, 2013, is used to hedge the variability in cash

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flows in monthly interest payments made on our $100.0 million one-month LIBOR-based borrowings (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate. Under the second collar, we capped our exposure at a maximum one-month LIBOR rate of 5.50% and established a minimum floor rate of 2.70%. The changes in the fair value of the second collar are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the one-month LIBOR rate above and below the second collar's strike rates. Changes in the fair values of the collars are recorded as either an asset or a liability with a corresponding amount recorded in accumulated other comprehensive income in the accompanying consolidated balance sheet.

        Forward Starting Swap—In October 2009, we executed a forward starting swap with a major financial institution. The swap, which will become effective on May 16, 2011 and expire on May 16, 2016, will be used to hedge the variability in interest payments due to changes in the one-month LIBOR swap curve with respect to $100.0 million of one-month LIBOR-based borrowings at a fixed rate of 3.93%. Hedge effectiveness was assessed at inception and will be assessed quarterly, prospectively and retrospectively, using regression analysis. The changes in the fair value of the swap are expected to be highly effective in offsetting the changes in interest rate payments attributable to fluctuations in the one-month LIBOR swap curve.

    Valuation of Intangibles and Other Long-Lived Assets

        We assess the carrying value of our long-lived assets, including intangible assets, whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Factors we consider important include, but are not limited to, significant underperformance relative to historical or projected future results, significant negative industry factors and significant changes in strategy or operations that negatively affect the utilization of our long-lived assets. If an impairment review is triggered, we evaluate the carrying value of intangible assets based on the projected cash flows of the particular asset. The amount of impairment, if any, is measured based on fair value, which is determined using projected discounted future operating cash flows. The cash flows that are used contain our best estimates, using appropriate and customary assumptions and projections at the time. If the cash flow estimates or the significant operating assumptions upon which they are based change in the future, we may be required to record additional impairment charges.

        We record accrued liabilities for all direct costs associated with the estimated resolution of contingencies at the earliest date at which it is deemed probable that a liability has been incurred and the amount of such liability can be reasonably estimated. Costs accrued are estimated based upon an analysis of potential results, assuming a combination of litigation and settlement strategies and outcomes.

        Estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Loss accruals are adjusted as further information becomes available or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized as assets when their receipt is deemed probable.

        We are subject to other contingencies, including legal proceedings and claims arising out of our businesses that cover a wide range of matters, including, among others, environmental matters, contract and employment claims. Environmental and other legal proceedings may also include matters with respect to businesses we previously owned. Further, due to the lack of adequate information and the potential impact of present regulations and any future regulations, there are certain circumstances in which no range of potential exposure may be reasonably estimated. Please read Item 3, "Legal Proceedings."

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        A discussion of related party transactions is included in Note 16 of Notes to Consolidated Financial Statements included elsewhere in this report.

Recent Accounting Pronouncements

        A description and related impact expected from the adoption of certain new accounting pronouncements is provided in Note 2 of Notes to Consolidated Financial Statements included elsewhere in this report.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk.

        Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity risk. We utilize two interest rate collars and a forward starting swap to manage exposure to interest rate risk and various derivative instruments to manage exposure to commodity risk.

        We utilize variable rate debt and are exposed to market risk due to the floating interest rates on our credit agreement. Therefore, from time to time, we utilize interest rate collars and swaps to hedge interest obligations on specific and anticipated debt issuances.

        On August 18, 2010, we amended our credit agreement. Please read Item 7, "Management's Discussion and Analysis—Liquidity and Capital Resources——Credit Agreement" for information on interest rates related to our borrowings.

        As of December 31, 2010, we had total borrowings outstanding under the credit agreement of $786.7 million. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of approximately $7.9 million annually, assuming, however, that our indebtedness remained constant throughout the year.

        We executed two zero premium interest rate collars with major financial institutions. Each collar is designated and accounted for as a cash flow hedge. The first collar, which became effective on May 14, 2007 and expires on May 14, 2011, is used to hedge the variability in interest payments due to changes in the three-month LIBOR rate with respect to $100.0 million of three-month LIBOR-based borrowings. Under the first collar, we capped our exposure at a maximum three-month LIBOR rate of 5.75% and established a minimum floor rate of 3.75%. Whenever the three-month LIBOR rate is greater than the cap, we receive from the respective financial institution the difference between the cap and the current three-month LIBOR rate on the $100.0 million of three-month LIBOR-based borrowings. Conversely, whenever the three-month LIBOR rate is lower than the floor, we remit to the respective financial institution the difference between the floor and the current three-month LIBOR rate on the $100.0 million of three-month LIBOR-based borrowings. As of December 31, 2010, the three-month LIBOR rate of 0.29% was lower than the floor rate. As a result, in January 2011, we remitted to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $452,300.

        On September 29, 2008, we executed our second zero premium interest rate collar. The second collar, which became effective on October 2, 2008 and expires on October 2, 2013, is used to hedge the variability in cash flows in monthly interest payments made on our $100.0 million one-month LIBOR-based borrowings (and subsequent refinancings thereof) due to changes in the one-month LIBOR rate. Under the second collar, we capped our exposure at a maximum one-month LIBOR rate of 5.50% and established a minimum floor rate of 2.70%. Whenever the one-month LIBOR rate is greater than the

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cap, we receive from the respective financial institution the difference between the cap and the current one-month LIBOR rate on the $100.0 million of one-month LIBOR-based borrowings. Conversely, whenever the one-month LIBOR rate is lower than the floor, we remit to the respective financial institution the difference between the floor and the current one-month LIBOR rate on the $100.0 million of one-month LIBOR-based borrowings. As of December 31, 2010, the one-month LIBOR rate of 0.26% was lower than the floor rate. As a result, in January 2011, we remitted to the respective financial institution the difference between the floor rate and the current rate which amounted to approximately $203,300.

        In addition, in October 2009, we executed a forward starting swap with a major financial institution. The swap, which will become effective on May 16, 2011 and expire on May 16, 2016, will be used to hedge the variability in interest payments due to changes in the one-month LIBOR swap curve with respect to $100.0 million of one-month LIBOR-based borrowings at a fixed rate of 3.93%.

        We hedge our exposure to price fluctuations with respect to refined petroleum products and blendstocks in storage and expected purchases and sales of these commodities. The derivative instruments utilized consist primarily of futures contracts traded on the NYMEX and the Chicago Mercantile Exchange and over-the-counter transactions, including swap agreements entered into with established financial institutions and other credit-approved energy companies. Our policy is generally to purchase only products for which we have a market and to structure our sales contracts so that price fluctuations do not materially affect our profit. While our policies are designed to minimize market risk, some degree of exposure to unforeseen fluctuations in market conditions remains. Except for the controlled trading program discussed below, we do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes that might expose us to indeterminable losses.

        While we seek to maintain a position that is substantially balanced within our product purchase activities, we may experience net unbalanced positions for short periods of time as a result of variances in daily sales and transportation and delivery schedules as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our business, we engage in a controlled trading program for up to an aggregate of 250,000 barrels of refined petroleum products and blendstocks at any one point in time.

        We enter into futures contracts to minimize or hedge the impact of market fluctuations on our purchases and forward fixed price sales of refined petroleum products. Any hedge ineffectiveness is reflected in our results of operations. We utilize regulated exchanges, including the NYMEX and the Chicago Mercantile Exchange, which are regulated exchanges for energy products that it trades, thereby reducing potential delivery and supply risks. Generally, our practice is to close all exchange positions rather than to make or receive physical deliveries. With respect to other energy products, which may not have a correlated exchange contract, we enter into derivative agreements with counterparties that we believe have a strong credit profile, in order to hedge market fluctuations and/or lock-in margins relative to our commitments.

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        At December 31, 2010, the fair value of all of our commodity risk derivative instruments and the change in fair value that would be expected from a 10% price increase or decrease are shown in the table below (in thousands):

 
   
  Gain (Loss)  
 
  Fair Value   Effect of 10%
Price Increase
  Effect of 10%
Price Decrease
 

NYMEX contracts

  $ (36,273 ) $ (55,604 ) $ 55,604  

Swaps, options and other, net

    (2,391 )   (6,693 )   1,139  
               

  $ (38,664 ) $ (62,297 ) $ 56,743  
               

        The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at December 31, 2010. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. All hedge positions offset physical exposures to the spot market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10% increase or decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10% change in prompt month prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. We have a daily margin requirement to maintain a cash deposit with our broker based on the prior day's market results on open futures contracts. The balance of this deposit will fluctuate based on our open market positions and the commodity exchange's requirements. The brokerage margin balance was $15.5 million at December 31, 2010.

        We are exposed to credit loss in the event of nonperformance by counterparties of futures contracts, forward contracts and swap agreements. We anticipate some nonperformance by some of these counterparties which, in the aggregate, we do not believe at this time will have a material adverse effect on our financial condition, results of operations or cash available for distribution to our unitholders. Futures contracts, the primary derivative instrument utilized, are traded on regulated exchanges, greatly reducing potential credit risks. Exposure on swap and certain option agreements is limited to the amount of the recorded fair value as of the balance sheet dates. We utilize primarily one clearing broker, a major financial institution, for all NYMEX derivative transactions and the right of offset exists. Accordingly, the fair value of all derivative instruments is displayed on a net basis.

Item 8.    Financial Statements and Supplementary Data.

        The information required here is included in the report as set forth in the "Index to Financial Statements" on page F-1.

Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

        None.

Item 9A.    Controls and Procedures.

        We maintain disclosure controls and procedures that are designed to ensure that the information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of

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1934 (the "Exchange Act") is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Under the supervision and with the participation of our principal executive officer and principal financial officer, management evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2010.

        We are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act). Internal control over financial reporting is the process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations in the effectiveness of internal control over financial reporting, including the possibility that misstatements may not be prevented or detected. Accordingly, even effective internal controls over financial reporting can provide only reasonable assurance with respect to financial statement preparation.

        Under the supervision and with the participation of our principal executive officer and principal financial officer, management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation, management believes that our internal control over financial reporting was effective as of December 31, 2010.

        In conducting its evaluation of the effectiveness of our internal control over financial reporting, management excluded the retail gas stations acquired in September 2010. The contribution from this acquisition represented approximately 15% of total assets, 4% of revenues and 5% of net income, respectively, of our consolidated financial statement amounts as of and for the year ended December 31, 2010.

        Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report on management's assessment of the effectiveness of our internal control over financial reporting, as stated in their report which is included herein.

        During the quarter ended December 31, 2010, our existing internal control framework was supplemented with an enhanced control process in relation to any new large, unique, or abnormal sales contracts and associated state and federal fuel taxes. Also during the quarter ended December 31, 2010, we initiated the process of integrating the internal controls and procedures related to our September 30, 2010 acquisition of retail gas stations into our internal control over financial reporting.

        Except as described above, there has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Global GP LLC
and Unitholders of Global Partners LP

        We have audited Global Partners LP's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Global Partners LP's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        As indicated in the accompanying Management's Annual Report, management's assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the retail gas stations acquired in September 2010, which are included in the 2010 consolidated financial statements of Global Partners LP and constituted approximately 15% of total assets as of December 31, 2010 and 4% and 5% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of Global Partners LP also did not include an evaluation of the internal control over financial reporting of the retail gas stations acquired in September 2010.

        In our opinion, Global Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Global Partners LP, as of December 31, 2010 and 2009, and the related consolidated statements of income, partners' equity and cash flows for each of the three years in the period ended December 31, 2010, and our report dated March 11, 2011 expressed an unqualified opinion thereon.

        /s/ ERNST & YOUNG LLP  

Boston, Massachusetts
March 11, 2011

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Item 9B.    Other Information.

        None.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance.

        Global GP LLC, our general partner, manages our operations and activities on our behalf. Our general partner is not elected by our unitholders and is not subject to re-election in the future. Affiliates of the Slifka family own 100% of the ownership interests in our general partner. Our general partner is controlled by Alfred A. Slifka and Richard Slifka through their beneficial ownership of entities that own ownership interests in our general partner. Eric Slifka beneficially owns an interest in our general partner. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse.

        Three members of the board of directors of our general partner serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. Members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence and experience standards established by the New York Stock Exchange ("NYSE") and the Securities Exchange Act of 1934. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we have a separately-designated standing audit committee established in accordance with the Securities Exchange Act of 1934 and a compensation committee. The three independent members of the board of directors of our general partner, Messrs. McKown, McCool and Watchmaker, serve as members of the conflicts, audit and compensation committees.

        Even though most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company and establish and maintain an audit committee, a compensation committee and a nominating/corporate governance committee, each consisting solely of independent directors, the NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or establish a compensation committee or a nominating/corporate governance committee.

        No member of the audit committee is an officer or employee of our general partner or director, officer or employee of any affiliate of our general partner. Furthermore, each member of the audit committee is independent as defined in the listing standards of the NYSE. The board of directors of our general partner has determined that a member of the audit committee, namely Kenneth Watchmaker, is an "audit committee financial expert" as defined by the SEC.

        Among other things, the audit committee is responsible for reviewing our external financial reporting, including reports filed with the SEC, engaging and reviewing our independent auditors and reviewing procedures for internal auditing and the adequacy of our internal accounting controls.

        We are managed and operated by the directors and executive officers of our general partner. Our operating personnel are employees of our general partner or certain of our operating subsidiaries.

        All of our executive officers devote substantially all of their time to managing our business and affairs, but from time to time perform services for certain of our affiliates. Messrs. Eric Slifka, Hollister, Faneuil and Rudinsky spend a portion of their time providing services to certain of our affiliates. Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence—Relationship of Management with Global Petroleum Corp. and Alliance Energy LLC." Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

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        The following table shows information for the directors and executive officers of our general partner.

Name
  Age   Position with Global GP LLC

Alfred A. Slifka

    78   Chairman

Richard Slifka

    70   Vice Chairman

Eric Slifka

    45   President, Chief Executive Officer and Director

Thomas J. Hollister

    56   Chief Operating Officer, Chief Financial Officer and Director

Edward J. Faneuil

    58   Executive Vice President, General Counsel and Secretary

Charles A. Rudinsky

    63   Executive Vice President and Chief Accounting Officer

David K. McKown

    73   Director

Robert J. McCool

    72   Director

Kenneth I. Watchmaker

    68   Director

        Alfred A. Slifka was elected Chairman of the Board of our general partner in March 2005. He has been employed with Global Companies LLC or its predecessors for over fifty years. Mr. Slifka served as Chairman of the board of directors of Global Companies LLC since its formation in December 1998. Currently Mr. Slifka is a member of, is employed by and serves as Chairman of the board of directors of Alliance Energy LLC, a privately held affiliated company that engages in the retail distribution of gasoline in the Northeastern United States and manages our retail gas stations. Mr. Slifka also is a shareholder, a director and the President of Global Petroleum Corp., a privately held affiliated company that owns, operates and leases to us our petroleum products storage terminal located in Revere, Massachusetts. Mr. Slifka currently serves on the boards of the New England Fuel Institute, Petroleum Institute Research Foundation, and Children's Hospital. He is a past member of the boards of directors of Citibank and Trust and of Griffiths Consumer Company, the board of overseers of Beth Israel Deaconess Hospital, and numerous other civic and charitable organizations. Mr. Slifka's extensive knowledge of the oil industry in general and of our history, customers and suppliers make him uniquely qualified to serve as our Chairman of the Board.

        Richard Slifka was elected Vice Chairman of the Board of our general partner in March 2005. He has been employed with Global Companies LLC or its predecessors since 1963. Mr. Slifka served as Treasurer and a director of Global Companies LLC since its formation in December 1998. Currently Mr. Slifka is a member of, is employed by and serves as Treasurer and Vice Chairman of the board of directors of Alliance Energy LLC, a privately held affiliated company that engages in the retail distribution of gasoline in the Northeastern United States and manages our retail gas stations. Mr. Slifka also is a shareholder, a director and the Treasurer of Global Petroleum Corp., a privately held affiliated company that owns, operates and leases to us our petroleum products storage terminal located in Revere, Massachusetts. Mr. Slifka currently serves on the boards of directors of New England Fuel Institute, Independent Fuel Terminal Operators Association (where he also serves as president), and National Oil Heat Research Alliance. He also currently serves on the board of directors of St. Francis House and the board of trustees of Boston Medical Center. He has been a director of the National Multiple Sclerosis Society since 1988. Mr. Slifka's extensive knowledge of the oil industry in general and of our history, customers and suppliers make him uniquely qualified to serve as our Vice Chairman of the Board. Alfred A. Slifka and Richard Slifka are brothers.

        Eric Slifka was elected President, Chief Executive Officer and a director of our general partner in March 2005. He has been employed with Global Companies LLC or its predecessors since 1987. Mr. Slifka served as President and Chief Executive Officer and a director of Global Companies LLC since July 2004 and as Chief Operating Officer and a director of Global Companies LLC from its formation in December 1998 to July 2004. Prior to 1998, Mr. Slifka held various senior positions in the accounting, supply, distribution and marketing departments of the predecessors to Global Companies LLC. Mr. Slifka is a member of the board of directors and an owner of Alliance

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Energy LLC, a privately held affiliated company that engages in the retail distribution of gasoline in the Northeastern United States and manages our retail gas stations. He currently serves as a member of the board of directors of the Mass Oil Heat Council, the National Oilheat Research Alliance and the Energy Policy Research Foundation. He also is a member of the boards of directors of the Cystic Fibrosis Foundation, Massachusetts Youth Committed to Winning, and Buckingham, Browne & Nichols. Mr. Slifka's extensive experience in all aspects of our business and his position as President and Chief Executive Officer of our general partner make him uniquely qualified to serve as a director of our general partner. Mr. Slifka is the son of Alfred A. Slifka and the nephew of Richard Slifka.

        Thomas J. Hollister was elected to serve as a director of our general partner in August 2009. He has served as Chief Operating Officer and Chief Financial Officer of our general partner since January 2007 and Chief Financial Officer of our general partner since July 2006, when he was first employed with our general partner. From 2005 to March 2006, Mr. Hollister served as Vice Chairman of Citizens Financial Group and as Chairman, President and Chief Executive Officer of Citizens Capital, Inc., Citizens Financial Group's private equity and venture capital business. From 2004 to 2005, he served as President and Chief Executive Officer of Charter One Bank. From 1998 to 2004 he served as President and Chief Executive Officer of Citizens Bank of Massachusetts. Mr. Hollister currently serves on the board of directors of Brookline Bancorp, where he serves as audit chair. He is the former chair of the Greater Boston Chamber of Commerce and currently serves on its Executive Committee. He is chair of the board of Tufts Medical Center and chair of the board of Wheaton College. He is chair of the Initiative for a New Economy. He previously served on the boards of directors of the Massachusetts Bankers Association, Macomber Construction Company, the Massachusetts Housing Investment Corporation, Savings Bank Life Insurance of Massachusetts and the Massachusetts Community & Banking Council (where he served as chair of the board). His extensive financial and executive experience, as well as his broad community ties, are assets for our board of directors.

        Edward J. Faneuil was elected Executive Vice President, General Counsel and Secretary of our general partner in March 2005. He has been employed with Global Companies LLC or its predecessors since 1991. Mr. Faneuil served as General Counsel and Secretary of Global Companies LLC since its formation in December 1998. He currently serves on the board of directors of New England Fuel Institute.

        Charles A. Rudinsky has served as Executive Vice President and Chief Accounting Officer of our general partner since January 2007. He has been employed with Global Companies LLC or its predecessors since 1988. Mr. Rudinsky served as Assistant Controller from 1988 to 1997 and as the Senior Controller and Chief Accounting Officer of Global Companies LLC since its formation in December 1998.

        David K. McKown was elected to serve as a director of our general partner and as a member of the conflicts committee, the compensation committee and the audit committee of the board of directors of our general partner in October 2005. He has been a Senior Advisor to Eaton Vance Management, whose principal business is creating, marketing and managing investment funds and providing investment management services to institutions and individuals, since 2000. In this capacity he serves as a credit analyst and a major research source for many of the changes in the accounting area, such as marked to market valuations, changes in bank lending rules and understanding of new financial products and derivatives. Mr. McKown retired in March 2000 having served as a Group Executive with BankBoston since 1993. Mr. McKown has been in the banking industry for over 40 years, where he acquired extensive accounting, financial structuring and negotiation skills, having worked at BankBoston for over 33 years as a Senior Credit Officer, the head of a workout unit, the head of BankBoston's energy lending group and the head of BankBoston's real estate and corporate finance departments. He also was a managing director of BankBoston's private equity unit. Mr. McKown has served on the boards of four public companies and four private companies in a variety of industries. He currently

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serves as a director of Safety Insurance Group, Newcastle Investment Co. and several private companies. Mr. McKown previously served as a member of the board of directors of Equity Office Properties. Mr. McKown's extensive financial expertise and longstanding work in BankBoston's energy practice make him well qualified to serve as a director of our general partner.

        Robert J. McCool was elected to serve as a director of our general partner, the chair of the conflicts committee of the board of directors of our general partner, and a member of the compensation and audit committees of the board of directors of our general partner in October 2005. He has been an Advisor to Tetco Inc., a privately held company in the energy industry, since 1967. Mr. McCool has been in the refined petroleum industry for over 40 years. He worked for Mobil Oil for 33 years in various positions including manager, planning and financial analysis, controller, manager U.S. lubricants operations and manager, budget and controls for U.S. acquisitions. Mr. McCool retired in 1998 having served as Executive Vice President responsible for Mobil Oil's North and South America marketing and refining business. Mr. McCool's extensive experience with the financial, accounting and managerial aspects of the refined petroleum products industry make him well qualified to serve as a director of our general partner.

        Kenneth I. Watchmaker was elected to serve as a director of our general partner, a member of the conflicts and compensation committees of the board of directors of our general partner, and chair of the audit committee of the board of directors of our general partner in October 2005. He subsequently became chair of our general partner's compensation committee as well. He served as Executive Vice President and Chief Financial Officer of Reebok International Ltd. from 1995 until March 2006, when he elected to retire in connection with the sale of Reebok International Ltd to adidas-Salomon AG. Mr. Watchmaker joined Reebok International Ltd. in July 1992 as Executive Vice President, Operations and Finance, of the Reebok Brand. Prior to joining Reebok International Ltd., he was an audit partner at Ernst & Young LLP., where he had various responsibilities including partner in charge of merger and acquisition services, regional partner in charge of bankruptcy and insolvency services and regional partner in charge of retail industry services. Mr. Watchmaker also serves as a director and the chair of the audit committee of American Biltrite Inc. Mr. Watchmaker's broad audit and accounting experience, as well as his significant corporate and financial experience as a senior executive with public companies, make him a valuable member of our board of directors.


Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Securities Exchange Act of 1934 requires directors and executive officers of our general partner and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 to file certain reports with the SEC and the NYSE concerning their beneficial ownership of such securities. Based solely upon a review of the copies of reports on Forms 3, 4 and 5 and amendments thereto furnished to us, or written representations that no reports on Form 5 were required, we believe that during the year ended December 31, 2010, the officers and directors of our general partner and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a),


Executive Sessions

        The board of directors of our general partner holds executive sessions for the non-management directors on a regular basis without management present. Since the non-management directors include directors who are not independent directors, the independent directors also meet in separate executive sessions without the other directors or management at least once each year to discuss such matters as the independent directors consider appropriate. In addition, any director may call for an executive session of non-management or independent directors at any board meeting. A majority of the independent directors selects a presiding director for any such executive session.

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Communications with Unitholders, Employees and Others

        Unitholders, employees and other interested persons who wish to communicate with the board of directors of our general partner, non-management or independent directors as a group, a committee of the board or a specific director may do so by transmitting correspondence addressed to the Board of Directors, Name of Director, Group or Committee, c/o Corporate Secretary, Global Partners LP, P.O. Box 9161, 800 South Street, Suite 200, Waltham, MA 02454-9161, Fax: 781-398-4165.

        Letters addressed to the board of directors of our general partner in general will be reviewed by the corporate secretary and relayed to the chairman of the board or the chair of the appropriate committee. Letters addressed to the non-management or independent directors in general will be relayed unopened to the chair of the audit committee. Letters addressed to a committee of the board of directors or a specific director will be relayed unopened to the chair of the committee or the specific director to whom they are addressed. All letters regarding accounting, accounting policies, internal accounting controls and procedures, auditing matters, financial reporting processes or disclosure controls and procedures are to be forwarded by the recipient director to the chair of the audit committee.


Code of Ethics

        Our general partner has adopted a code of business conduct and ethics that applies to all officers, directors and employees of our general partner, including the principal executive officer, principal financial officer and principal accounting officer, and to our subsidiaries and their officers, directors and employees.

        A copy of the code of business conduct and ethics is available on our website at www.globalp.com or may be obtained without charge upon written request to the General Counsel at: Global Partners LP, P.O. Box 9161, 800 South Street, Suite 200, Waltham, MA 02454-9161.


Corporate Governance Matters

        The NYSE requires the Chief Executive Officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of our general partner provided such certification to the NYSE in 2010.

        The certifications of our general partner's Chief Executive Officer and Chief Financial Officer required by the Securities Exchange Act of 1934 are included as exhibits to this Annual Report on Form 10-K.

Item 11.    Executive Compensation.

        All of our executive officers and substantially all of our employees are employed by our general partner. Our general partner does not receive any management fee or other compensation for its management of Global Partners LP. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, executive officer and director compensation and benefits properly allocable to Global Partners LP, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, Global Partners LP. Our partnership agreement provides that our general partner will determine the expenses that are allocable to Global Partners LP.

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Compensation Discussion and Analysis

        We are managed and operated by the directors and executive officers of our general partner. Executive officers of our general partner receive compensation in the form of salaries and short-term incentive awards (contractual and/or discretionary) and long-term incentive awards, and they are eligible to participate in employee benefit plans and arrangements sponsored by our general partner or its affiliates, including plans that may be established by our general partner or its affiliates in the future. Our named executive officers (defined below) serve as executive officers of our general partner and each of our subsidiaries, and the compensation described herein reflects their total compensation for services to us, our general partner and our subsidiaries.

        Our "named executive officers" include Mr. Eric Slifka, our Chief Executive Officer ("CEO"), Mr. Thomas J. Hollister, our Chief Financial Officer ("CFO") and Chief Operating Officer, and the two other most highly compensated executive officers during 2010, who are Mr. Charles A. Rudinsky, our Executive Vice President and Chief Accounting Officer, and Mr. Edward J. Faneuil, our Executive Vice President and General Counsel. Messrs. Slifka, Hollister and Faneuil are parties to employment agreements with our general partner. Mr. Rudinsky is an employee at will with no employment agreement.

        The compensation committee of the board of directors of our general partner (the "Compensation Committee") has direct responsibility for the compensation of our CEO based upon (i) contractual obligations pursuant to the employment agreement between our CEO and our general partner, and (ii) compensation parameters established by the Compensation Committee with respect to salary adjustments, incentive plans and discretionary bonuses, if any. The Compensation Committee also has oversight and approval authority for the compensation of our named executive officers other than our CEO based upon our CEO's recommendations, including awards under any incentive plans in which the named executive officers participate, and our general partner's contractual obligations pursuant to employment agreements with two of our named executive officers.

Compensation Objectives

        The objectives of our compensation program with respect to our executive officers are to attract, engage and retain individuals with the requisite knowledge, experience and skill sets required for our future success. Our compensation program is intended to motivate and inspire employee behavior that fosters high performance, and to support our overall business objectives. To achieve these objectives, we aim to provide each executive officer with a competitive total compensation program. We currently utilize the following compensation components:

    Salaries and benefits designed to attract and retain high caliber employees;

    Short-term, performance-based incentives and discretionary bonus awards designed to focus employees on key business objectives for a particular year; and

    Long-term, equity-based incentive awards designed to support the achievement of our long-term business objectives and the retention of key personnel.

Compensation Methodology

        Our general partner uses third-party consultants to study and supply market comparable compensation data and to assist our management and the Compensation Committee in formulating competitive compensation plans. In 2008, our general partner engaged W.F. Conover III, Ltd. as an independent compensation consultant to provide advice and assistance to the Compensation Committee on matters related to named executive officer compensation as well as our general compensation programs (i.e., short-term and long-term incentive programs). In 2009, Michael Conover, the principal at W.F. Conover III, Ltd. who provided consulting services to our general partner, moved to BDO

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Seidman, LLP. References to "Conover" hereinafter mean our compensation consultant, whether the consulting services were provided through W.F. Conover III, Ltd. or BDO Seidman, LLP.

        Conover has continued to work with our management and the Compensation Committee to assess the competitiveness of our executive compensation program using a comprehensive, broad-based analysis of market information. In 2010 Conover utilized the following data sources to develop and update overall consensus values for executive compensation prepared in prior years. The following data sources were utilized to complete this update: (i) data from the Watson Wyatt Worldwide Executive Compensation Survey; (ii) data with respect to a group of more than 220 companies with market capitalizations of $200 million to $600 million, a range which was comparable to our market capitalization at the time of the study; and (iii) data with respect to a multi-factor based group of 17 energy and non-energy companies which had market capitalizations of $200 million to $600 million and between 100 to 600 employees. Conover also examined the responsibilities assigned to each of our named executive officer positions in relation to the external positions to which they were compared, exercised judgment in terms of the relevance of each of the market data sources, and made adjustments to arrive at a competitive market benchmark for each executive position.

        Data included in the Watson Wyatt Worldwide Executive Compensation Survey are provided with respect to energy companies as a group, but not individually by name, and, therefore, we are unable to provide a list of these companies.

        The multi-factor based group of 17 energy and non-energy companies referenced above includes:

      American Ecology Corp.
      American Vanguard Corp.
      Aventine Renewable Energy
      Balchem Corp.
      Electro Rent Corp.
      EnergySouth, Inc.
      Flotek Industries Inc.
      Fuel Tech, Inc.
      Houston Wire & Cable Co.
      Metalico Inc.
      Penford Corp.
      Pioneer Companies Inc.
      Semco Energy Inc.
      Symyx Technologies Inc.
      Topps Co. Inc.
      Uranium Resources Inc.
      Verenium Corp.

        In 2010, Conover also worked with our Compensation Committee to structure our short-term incentive plan for our named executive officers for 2011. The plan is structured to support the overall objectives of our compensation program by linking a significant portion of our named executive officers' compensation to our short-term business goals. The performance levels used in our 2011 short-term incentive plan for determination of the performance-based portion of the award were changed. The threshold minimum level of performance required to qualify for any award was increased. Likewise, the target "par" and maximum performance levels used for determination of the performance-based portion of the award also were increased. In addition, the award amounts associated with performance levels used for the performance-based portion of our short-term incentive plan were changed. Award amounts at or just above the threshold minimum performance level were lowered, and award levels closer to the target "par" were increased to provide a greater incentive to reach target "par" performance. Similarly, awards just above the target "par" range were lowered and award levels

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closer to the maximum performance level significantly increased to provide greater incentive for results that significantly exceed target "par" performance. Conover also assisted the Compensation Committee with an analysis of the portion of our partnership's common units reserved for compensation purposes versus competitive practices, and provided a preliminary overview in connection with the development of a new long-term executive retention plan.

Elements of Compensation

        Our executive compensation structure utilizes complementary components to align our compensation with the needs of our business and to provide for desired levels of pay that competitively compensate our executive management personnel. We administer the program on the basis of total compensation. When our performance goals are met, we expect the total compensation levels (i.e., salary plus short and long-term incentives) for our named executive officers to fall between the median (50th percentile) and 75th percentile compensation levels in our competitive marketplace. When we perform above or below our performance goals, we expect that will be reflected in our compensation levels.

        The elements of the 2010 executive officer compensation of our general partner are base salary, discretionary bonuses, short-term incentive awards, retirement and health benefits, and perquisites consistent with those provided to executive officers generally and as may be approved by the Compensation Committee from time to time.

        A description of the components of the compensation program and principles used to guide their administration appears below:

Salaries

        Under our executive compensation structure, our goal is for our named executive officer salaries to fall between the median (50th percentile) and 75th percentile of competitive salary levels following any adjustments made to marketplace pay levels in order to account for significant responsibilities that are assigned to our named executive officers and that exceed the scope of responsibilities generally associated with the external benchmark positions to which they are compared, specifically:

    Our Chief Financial Officer also serves as our Chief Operating Officer ("COO") and, as such, has responsibilities for many operational areas that are not commonly assigned to Chief Financial Officer positions.

    Our Executive Vice President and General Counsel is responsible for all our environmental compliance functions, many of our human resources matters, and many of our business transactions that he manages in an executive as well as legal capacity.

    Our Executive Vice President and Chief Accounting Officer, who also serves as co-director of our mergers and acquisitions activities, is responsible for our financial analyses for our acquisition due diligence.

        Base salaries for three of our four named executive officers are set by the terms of their respective employment agreements. Salaries for our named executive officers were not increased in 2010.

Short-Term Incentive Awards—Contractual

        Thomas Hollister, our COO and CFO, is entitled to annual contractual bonuses under his employment agreement with our general partner based upon our achievement of specific targets established by the Compensation Committee. Mr. Hollister was not entitled to a contractual bonus in 2008 because the distributable cash flow target established by the Compensation Committee for 2008 was not achieved. In 2009, the Compensation Committee implemented our general partner's

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Short-Term Incentive Plan (see Short-Term Incentive Plan). Prior to the Compensation Committee's determination of Mr. Hollister's awards for each of 2009 and 2010 under our general partner's Short-Term Incentive Plan, Mr. Hollister waived his annual contractual bonuses for those years. For each of 2009 and 2010, Mr. Hollister was paid a bonus under our general partner's Short-Term Incentive Plan in an amount in excess of what he would have received as a contractual bonus under his employment agreement with our general partner.

Annual Bonuses—Discretionary

        Our compensation program for named executive officers contains a provision for the Compensation Committee to award a discretionary bonus to recognize significant contributions made by an executive in the course of the year. Typically, these are one-time awards and not associated with any of our incentive plans. The Compensation Committee may make discretionary bonus awards to our CEO. Our CEO may also recommend discretionary bonus awards for all other named executive officers for consideration and approval by the Compensation Committee for similar purposes.

        The Compensation Committee elected to not award any discretionary bonus payments in respect of 2008 and 2010. Consequently, no discretionary bonus payments were awarded to our named executive officers for 2008 or for 2010.

        For 2009, the Compensation Committee awarded discretionary bonuses of $115,000 and $50,000, respectively, to Messrs. Hollister and Faneuil. These bonuses recognized Mr. Hollister's and Mr. Faneuil's successful accomplishment of several critical objectives for the Partnership during 2009.

Short-Term Incentive Plan

        Our general partner established a cash bonus pool for 2010 to fund short-term incentive awards for each of our named executive officers. Target awards under our general partner's short-term incentive plan for 2010 (the "STIP") included a performance-based component, for which 60% of the cash bonus pool was available (the "STIP Performance Component"), and a discretionary component, for which 40% of the cash bonus pool was available (the "STIP Discretionary Component"). Incentive awards earned under the STIP were based on the Partnership's actual performance in relation to a specified objective for distributable cash flow established by our Compensation Committee in February 2010 (the "DCF objective"), as adjusted by the Compensation Committee to reflect several factors that affected the Partnership's performance in 2010. Under our general partner's Short-Term Incentive Plan, for purposes of determining whether a specified target was achieved, "distributable cash flow" (a non-GAAP financial measure used by management) means our net income plus depreciation and amortization, less our maintenance capital expenditures.

        Under the STIP, each of our named executive officers was assigned an incentive target value expressed as a percentage of his base salary. The 2010 incentive target values were: 100% (or $800,000) for Mr. Slifka; 58% (or $337,500) for Mr. Hollister; 37% (or $137,500) for Mr. Faneuil; and 41% or ($112,500) for Mr. Rudinsky. 60% of the target value for each named executive officer was allocated to his STIP Performance Component (the "60% Performance-Based Payout Target"), and 40% was allocated to his STIP Discretionary Component (the "40% Discretionary Payout Target").

        STIP Performance Component (60% of the award opportunity):    Under the terms of the STIP, 100% of the STIP Performance Component is earned when the DCF objective is achieved. However, the STIP also provides for an increased payout under the STIP Performance Component when the DCF objective is exceeded, and a reduced payout under the STIP Performance Component when the DCF objective is not achieved. Such increases and reductions in payouts are determined in accordance with an award payout grid adopted by the Compensation Committee at the time that the STIP was established. Although the Partnership achieved the DCF objective for 2010 of $46.0 million (which DCF objective was established in February 2010), the Compensation Committee concluded that the

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Partnership's 2010 acquisitions, which occurred during the second and third quarters of 2010, should be taken into account. Furthermore, the Partnership would only have achieved less than the DCF objective if the results from its acquisition of the Mobil-branded retail gasoline stations and supply rights were excluded. Accordingly, in accordance with the payout grid established by the Compensation Committee at the time that the STIP was established, the STIP Performance Component of the named executive officers' 2010 awards was adjusted downward to approximately one-third of each named executive officer's 60% Performance-Based Payout Target.

        STIP Discretionary Component (40% of the award opportunity):    The STIP Discretionary Component is intended to be used as a discretionary award, allowing the Compensation Committee to supplement the performance metric by analyzing other factors that it may elect to use for determining the STIP Performance Component. Such factors include, without limitation, market factors and significant acquisitions, developments and ventures accomplished by the Partnership. The Compensation Committee awarded 100% of the STIP Discretionary Component for 2010 in recognition of each named executive officer's successful efforts in consummating the 2010 acquisitions, the Partnership's earning of the highest distributable cash flow in its history, and the Partnership's overall 2010 performance despite adverse market conditions and fewer advantageous buying opportunities that occurred during the fourth quarter of 2010.

        Each of our named executive officers earned a short-term incentive award for 2010. A summary of these awards appears in the table below:

Name
   
  Target Value
as a
Percentage
of Salary
  Target Value
($)
  2010 Award
Payouts
($)
 

Eric Slifka

  Total Award     100%     800,000     480,000  

  Performance     60%     480,000     160,000  

  Discretionary     40%     320,000     320,000  

Thomas J. Hollister

 

Total Award

   
58%
   
337,500
   
202,500
 

  Performance     35%     202,500     67,500  

  Discretionary     23%     135,000     135,000  

Edward J. Faneuil

 

Total Award

   
37%
   
137,500
   
82,500
 

  Performance     22%     82,500     27,500  

  Discretionary     15%     55,000     55,000  

Charles A. Rudinsky

 

Total Award

   
41%
   
112,500
   
67,500
 

  Performance     25%     67,500     22,500  

  Discretionary     16%     45,000     45,000  

Long-Term Incentive Plan

        2008 CEO Award.    On December 31, 2008, pursuant to a contractual commitment in Eric Slifka's employment agreement with our general partner, the Compensation Committee granted to Mr. Slifka 99,700 phantom units together with a contingent right to receive an amount in cash equal to the number of then outstanding phantom units granted to Mr. Slifka multiplied by the cash distributions per common unit made by the Partnership from time to time during the period the phantom units are outstanding. The phantom units vest in six approximately equal installments on June 30 and December 31 of 2009, 2010 and 2011; provided, however, that in accordance with the terms of Mr. Slifka's employment agreement, if Mr. Slifka's employment is terminated (i) for reason of death or disability, or (ii) without cause or for constructive termination, in either case within 12 months following a change in control, then all unvested phantom units shall vest on the applicable termination date. Additionally, if Mr. Slifka's employment is terminated without cause or for constructive

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termination but such termination does not occur within 12 months following a change in control, then a prorated portion of the phantom units scheduled to vest at the end of the then applicable six-month period will vest on the date of termination, such proration to be based upon the number of full months' service provided by Mr. Slifka during such six-month period. In accordance with Mr. Slifka's employment agreement, 16,617 phantom units vested on each of June 30 and December 31 of 2009 and 2010. The general partner delivered to Mr. Slifka common units that it purchased in the open market and cash (to the extent not used by Mr. Slifka to satisfy his tax obligations in respect of the award) in payment for the vested phantom units.

        2009 Awards.    On February 5, 2009, the Compensation Committee granted 88,183, 61,728, 48,501 and 17,637 phantom units (without DERs) under the LTIP, respectively, to Messrs. Eric Slifka, Hollister, Faneuil and Rudinsky. Grant levels were established by the Compensation Committee to achieve the overall objectives of the compensation program.

        The phantom units granted in 2009 will vest and become payable on a one-for-one basis in common units (and/or cash in lieu thereof) on December 31, 2013 (or potentially sooner as described below). All or a portion of the phantom units granted to our named executive officers may vest earlier than December 31, 2013 if the Average Unit Price (as defined below) equals or exceeds specified target prices during specified periods. Specifically, if the Average Unit Price equals or exceeds: (i) $21.00 at any time prior to December 31, 2013, then 25% of the phantom units will automatically vest; (ii) $27.00 at any time during the period from February 5, 2011 through December 31, 2013, then an additional 25% of the phantom units will automatically vest; and (iii) $34.00 at any time during the period from June 5, 2012 through December 31, 2013, then all of the remaining phantom units will automatically vest. "Average Unit Price" means the closing market price per common unit for any 10-consecutive trading day period.

        The phantom units granted to Mr. Slifka on February 5, 2009 that do not otherwise vest early as described above will be subject to a performance goal. Specifically, any unvested phantom units held by Mr. Slifka on December 31, 2013 will vest only if the Partnership makes cumulative distributions on all units of the Partnership outstanding during the 20 consecutive quarters ending December 31, 2013 in an amount equal to or exceeding the minimum quarterly distribution (as defined in the Partnership's Agreement of Limited Partnership) on all such units.

        Any phantom units granted on February 5, 2009 that have not vested as of the end of the five year cliff vesting period will be forfeited. Additionally, upon a change of control event (as defined in the grant, as amended), all outstanding phantom units that were granted on February 5, 2009 to Messrs. Slifka, Hollister and Faneuil only and that have not otherwise vested automatically will become fully vested (in the case of the phantom units awarded to Mr. Slifka, without regard to the achievement of the performance goal.)

        A portion (25%) of the February 5, 2009 phantom units vested on August 21, 2009 when the Compensation Committee determined that the first Average Unit Price condition ($21.00 for 10 consecutive trading days) was satisfied. The general partner delivered common units that it purchased in the open market to the named executive officers in payment for these vested phantom units.

        A second portion (25%) of the February 5, 2009 phantom units vested on February 18, 2011 when the Compensation Committee determined that the second Average Unit Price condition ($27.00 for 10 consecutive trading days) was satisfied. The general partner delivered common units that it had purchased in the open market to the named executive officers in payment for these vested phantom units.

        Further vesting opportunities for 2009 awards will become available after June 5, 2012 based upon the unit price performance criteria associated with the award.

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Retirement and Health Benefits; Perquisites

        Each of our named executive officers is eligible to participate in our general partner's health insurance plans, pension plans, 401(k) savings and profit sharing plan and other employee benefit plans in accordance with our general partner's policies and on the same general basis as other employees of our general partner. Under the general partner's pension plan, an employee becomes fully vested in his or her pension benefits after completing five years of service or upon termination due to death, disability or retirement. See "Other Benefits—Pension Benefits" for information with respect to eligibility standards and calculations of estimated annual pension benefits payable upon retirement under the pension plan. Our general partner's pension plan was frozen on December 31, 2009. Our general partner's 401(k) savings and profit sharing plan provides for discretionary matching contributions by our general partner equal to 50% of each employee's contribution, up to a maximum contribution of 4% of the employee's pre-tax annual compensation, subject to certain limitations under federal law. See "Other Benefits—401(k) Savings and Profit Sharing Plan" for additional information with respect to eligibility and permitted contributions to this plan. Additional perquisites for our named executive officers may include payment of premiums for supplemental life and/or long-term disability insurance, automobile fringe benefits, club membership dues and payment of fees for professional financial planning and/or tax advice.

Relationship of Compensation Elements to Compensation Objectives

        We use base salaries to provide financial stability and to compensate our executive officers for fulfillment of their respective job duties.

        We use a short-term incentive plan with performance-based and discretionary components to align a significant portion of our executive officers' compensation with annual business performance and success, and to provide rewards and recognition for key annual business and financial results such as achieving increased quarterly distributions, expanding our terminalling storage capacity, retail gasoline station assets and the geographic markets that we serve, and diversifying our product mix to enhance profitability and effectively managing our business. Short-term performance-based incentives also allow flexibility to reward performance and individual success consistent with such criteria as may be established from time to time by our CEO and the Compensation Committee.

        The long-term incentive plan provides incentive and rewards eligible participants for the achievement of long-term objectives, facilitates the retention of key employees by investing in our long-term performance, continues to make our compensation mix more competitive, and aligns the interests of management with those of our unitholders.

        We offer a mix of traditional perquisites such as automobile fringe benefits and country/golf club memberships, and additional benefits, such as payment of professional financial planning and tax advice fees, that are tailored to address our executive officers' individual needs to facilitate the performance of their job duties and to be competitive with the total compensation packages available to executive officers generally.

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Compensation of Named Executive Officers

        The following table sets forth certain information with respect to compensation of our Chief Executive Officer, our Chief Financial Officer and the two other most highly compensated executive officers during 2010, 2009 and 2008.


Summary Compensation Table

Name and Principal Position
  Year   Salary
($)
  Bonus
($)(2)
  Stock
Awards
($)(3)
  Non-Equity
Incentive Plan
Compensation
($)(4)
  Change in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings
($)
  All Other
Compensation
($)(6)
  Total
($)
 

Eric Slifka

    2010     800,000             480,000     56,781     93,798     1,430,579  
 

President and

    2009     800,000         1,147,261     1,032,968     34,648     80,313     3,095,190  
 

CEO(1)(7)

    2008     1,049,889         1,126,610         39,908     82,576     2,298,983  

Thomas J. Hollister

   
2010
   
578,000
   
   
   
202,500
   
14,862
   
34,739
   
830,101
 
 

COO and

    2009     578,000     115,000     803,081     435,784     24,637     40,184     1,996,686  
 

CFO(8)

    2008     577,500                 25,680     26,779     629,959  

Edward J. Faneuil

   
2010
   
376,000
   
   
   
82,500
   
235,024
   
52,799
   
746,323
 
 

EVP, General Counsel and

    2009     376,000     50,000     630,998     177,541     224,953     48,963     1,508,455  
 

Secretary(5)(9)

    2008     375,953                 64,782     27,783     468,518  

Charles A. Rudinsky

   
2010
   
273,000
   
   
   
67,500
   
359,227
   
34,891
   
734,618
 
 

EVP and Chief Accounting

    2009     273,000         229,457     125,261     372,687     34,507     1,034,912  
 

Officer(5)(10)

    2008     273,000                 136,180     15,272     424,452  

(1)
The above table reflects the 2008 compensation paid to Mr. Slifka pursuant to his employment agreement with our general partner that expired on December 31, 2008. On December 31, 2008, Mr. Slifka entered into a new employment agreement with our general partner, pursuant to which his base salary was reduced to $800,000.

(2)
These discretionary bonuses represent the amounts paid to the named executive officers by our general partner in 2010 for services performed during 2009. In 2010, Mr. Hollister and Mr. Faneuil were paid discretionary bonuses of $115,000 and $50,000, respectively, for services performed during 2009, which discretionary bonuses were in addition to the payments they received for services performed during 2009 under the 2009 Short-Term Incentive Plan. No discretionary bonuses were paid for services performed during 2008 and 2010.

(3)
In accordance with accounting guidance related to stock-based compensation, the dollar values shown in the "Stock Awards" column represent the grant date fair value of awards as described below:
    (a)
    LTIP—2009 Awards.    On February 5, 2009, the Compensation Committee granted awards of 88,183, 61,728, 48,501 and 17,637 phantom units, respectively, to Messrs. Slifka, Hollister, Faneuil and Rudinsky. Twenty-five percent of these phantom units (22,046, 15,432, 12,125 and 4,409, respectively) vested on August 21, 2009 and were paid on a one-for-one basis in our common units. See "Elements of Compensation—Long-Term Incentive Plan" for the terms of the 2009 Awards.

    (b)
    LTIP—2008 CEO Award.    On December 31, 2008, pursuant to Mr. Slifka's employment agreement with our general partner, the Compensation Committee granted Mr. Slifka an award of 99,700 phantom units which have vested or will vest in six approximately equal installments on June 30, 2009, December 31, 2009, June 30, 2010, December 31, 2010, June 30, 2011 and December 31, 2011. See "Elements of Compensation—Long-Term Incentive Plan" for the terms of the 2008 CEO Award.

    (c)
    LTIP—2007 Awards.    On August 14, 2007, the Compensation Committee granted awards of 24,541, 9,120, 7,976 and 3,927 phantom units and associated DERs, respectively, to Messrs. Slifka, Hollister, Faneuil and Rudinsky. These phantom units and associated DERs vested on December 31, 2009. The phantom units were paid in March 2010 in common units purchased by our general partner on the open market and, in April 2010, cash was paid (to the extent not used to satisfy the recipient's tax obligations in respect of the award.)

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      Using the vesting date price of $24.80 per unit, the 24,541, 9,120, 7,976 and 3,927 common units received by Messrs. Slifka, Hollister, Faneuil and Rudinsky, respectively, were valued at $608,617, $226,176, $197,805 and $97,390, and the associated DERs were valued at $119,619, $44,453, $38,877 and $19,141. See "Elements of Compensation—Long-Term Incentive Plan" for the terms of the 2007 Awards.

(4)
The bonuses paid to each of the named executive officers for services performed during 2009 and 2010 were determined in accordance with our general partner's Short-Term Incentive Plan described above under Elements of Compensation—Short-Term Incentive Plan.

(5)
With respect to Messrs. Faneuil and Rudinsky, the amounts shown under "Change in Pension Value and Nonqualified Deferred Compensation Earnings" include $159,355 and $277,318, respectively, representing the full amounts they each would receive on a lump sum basis under their respective supplemental executive retirement plan ("SERP) agreements with our general partner. Mr. Faneuil's interest in his SERP benefit will fully vest on December 31, 2014, to the extent he remains continuously employed with our general partner through such date. Mr. Rudinsky's interest in his SERP benefit will fully vest on July 19, 2012, to the extent he remains continuously employed with our general partner through such date. See Elements of Compensation—Supplemental Executive Retirement Plan Agreements for additional information regarding the SERP agreements.

(6)
All of our named executive officers are eligible to participate in our general partner's health insurance, pension, 401(k) and other employee benefit plans in accordance with our general partner's policies and on the same general basis as other employees of our general partner. See "Other Benefits—Pension Benefits" for information with respect to eligibility standards and calculations of estimated annual pension benefits payable upon retirement. Our general partner's 401(k) Savings and Profit Sharing Plan provides for discretionary matching contributions to the plan by our general partner. See "Other Benefits—401(k) Savings and Profit Sharing Plan" for additional information with respect to eligibility and permitted contributions to this plan.

(7)
With respect to Mr. Slifka, "All Other Compensation" for the years ended December 31, 2010, 2009 and 2008 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under the 401(k) plan; the estimated personal value of an automobile provided by us for Mr. Slifka's use; life insurance and long-term disability insurance premiums paid by us; club memberships; and professional financial planning and tax advice fees in the aggregate amount of $34,750 for 2010, and at levels below $25,000 for 2009 and 2008, paid by us.

(8)
With respect to Mr. Hollister, "All Other Compensation" for the years ended December 31, 2010, 2009 and 2008 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under the 401(k) plan; the estimated personal value of an automobile provided by us for Mr. Hollister's use; and long-term disability insurance premiums paid by us.

(9)
With respect to Mr. Faneuil, "All Other Compensation" for the years ended December 31, 2010, 2009 and 2008 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under the 401(k) plan; the estimated personal value of an automobile provided by us for Mr. Faneuil's use; long-term disability insurance premiums paid by us; and club membership fees paid by us.

(10)
With respect to Mr. Rudinsky, "All Other Compensation" for the years ended December 31, 2010, 2009 and 2008 includes the following perquisites in connection with his employment by our general partner: employer contributions paid by us under the 401(k) plan; the estimated personal value of an automobile provided by us for Mr. Rudinsky's use; and life insurance and long-term disability insurance premiums paid by us.

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Grants of Plan-Based Awards

        On March 8, 2011, the Compensation Committee awarded the following cash awards under our general partner's Short-Term Incentive Plan to our named executive officers in consideration of their respective services during the year ended December 31, 2010:

Name
  Non-Equity
Incentive Plan
Awards
$
 

Eric Slifka

    480,000  

Thomas J. Hollister

    202,500  

Edward J. Faneuil

    82,500  

Charles A. Rudinsky

    67,500  

        These awards were payable immediately without restrictions. See "Elements of CompensationShort-Term Incentive Plan" for a discussion of the parameters on which the 2010 awards were determined.

        The following table presents equity awards in the form of phantom units granted (i) under the LTIP to Mr. Slifka on December 31, 2008 pursuant to his employment agreement with our general partner, and (ii) under the LTIP to the named executive officers on February 5, 2009. The awards shown on the table below are all of the equity awards held by the named executive officers at the end of the last fiscal year:

 
  Equity Incentive Plan Awards  
 
  Number of
Unearned Shares,
Units or Other
Rights That Have
Not Vested
(#)
  Market or Payout
Value of Unearned
Shares, Units or
Other Rights That
Have Not Vested
($)(1)
 

Eric Slifka

    99,369     2,722,711  

Thomas J. Hollister

    46,296     1,268,510  

Edward J. Faneuil

    36,376     996,702  

Charles A. Rudinsky

    13,228     362,447  

(1)
The market values of the equity awards shown in the table above were calculated based on the closing price of $27.40 per common unit on December 31, 2010.

        See "Elements of Compensation—Long-Term Incentive Plan" for a discussion of the plan.

    Restricted Units Vested

        No restricted unit awards to named executive officers vested during the year ended December 31, 2010 and there were no options outstanding to named executive officers during 2010.

Employment and Related Agreements

        Eric Slifka is employed as President and Chief Executive Officer pursuant to an employment agreement with our general partner. The term of his initial employment agreement commenced on October 4, 2005 and continued through December 31, 2008. Effective December 31, 2008, Mr. Slifka entered into a new employment agreement with our general partner which amends, restates and supersedes his initial employment agreement. Unless terminated earlier in accordance with the terms of his new employment agreement, the term of the agreement ends on December 31, 2011 and, unless

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either party sends a notice of non-renewal to the other party, the agreement will automatically renew for an additional 36 months commencing January 1, 2012.

        The agreement provides for a base salary of $800,000 per year, subject to increase as of each January 1 during the term, as may be determined by the Compensation Committee. In addition, the agreement provides that Mr. Slifka: is (a) eligible to receive a cash bonus, payable annually, no later than two and one-half months after each fiscal year end in an amount to be determined at the discretion of the Compensation Committee; (b) entitled to participate in our general partner's short-term incentive compensation plan, pursuant to which he shall be entitled to receive cash incentive amounts to be determined based upon the achievement of financial metrics to be established by the Compensation Committee in the first month of each fiscal year during the term of the agreement, with the annual "award target" amount being 100% of his base salary and the annual maximum cash incentive amount being 200% of his base salary; any such awards to be paid within two and one-half months after the applicable fiscal year end; and (c) entitled to participate in our general partner's LTIP, including without limitation (i) the December 31, 2008 grant to Mr. Slifka of 99,700 phantom units (with a contingent right to receive cash in amounts equal to the number of awarded phantom units outstanding multiplied by the cash distributions per common unit made by the Partnership from time to time), and (ii) the February 5, 2009 grant to Mr. Slifka of 88,183 performance-restricted phantom units under the LTIP. See "Elements of Compensation—Long-Term Incentive Plan." As determined by the Compensation Committee, Mr. Slifka also may be eligible to participate in any other incentive plans in which management employees may participate. He is entitled to participate in such other benefit plans and programs as the general partner may provide for its executives in general.

        Mr. Slifka's employment agreement includes a confidentiality provision which, subject to typical exceptions for requirements of law and public knowledge (other than as a result of unauthorized disclosure by Mr. Slifka), will continue for two years following Mr. Slifka's termination of employment. The agreement also includes a nonsolicitation provision, which will continue for one year following Mr. Slifka's termination of employment. The agreement is subject to the non-competition provisions included in the Omnibus Agreement dated October 4, 2005 (and filed as Exhibit 10.1 to the Partnership's Form 8-K filed on October 11, 2005), which non-competition obligations shall continue to apply to Mr. Slifka throughout the term of his employment agreement (including the renewal term, if any) and, in the event Mr. Slifka's employment with our general partner is terminated (x) by our general partner without cause or by Mr. Slifka for reasons constituting constructive termination, (y) by our general partner for cause, or (z) by Mr. Slifka for reasons other than constructive termination, the non-competition provisions included in the Omnibus Agreement shall remain in effect for one year following Mr. Slifka's termination of employment. See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Slifka's employment agreement, as amended, relating to termination, change in control and related payment obligations.

        Thomas J. Hollister is employed as Chief Operating Officer and Chief Financial Officer of our general partner. Mr. Hollister's employment commenced effective July 1, 2006 and is on an "at will" basis, meaning that Mr. Hollister's employment has no specific duration and that, subject to the provisions of his employment agreement, either Mr. Hollister or our general partner may terminate his employment at any time for any reason. The agreement provides for a base salary of $550,000 for the initial 12-month period commencing July 1, 2006, and subsequent review by the Compensation Committee no less frequently than annually, at which time Mr. Hollister's base salary may be increased at the discretion of the Compensation Committee. In 2010, Mr. Hollister's base salary was $578,000. Mr. Hollister also is eligible to receive an annual cash bonus amount of $130,000 for each 12-month period that he is employed by our general partner, provided that we achieve a distributable cash flow target set by the Compensation Committee. No such bonus was earned in respect of calendar year 2008. Prior to the Compensation Committee's determination of Mr. Hollister's awards for each of 2009 and 2010 under our general partner's Short-Term Incentive Plan, Mr. Hollister waived his annual contractual bonuses for those years. Under our general partner's short-term incentive plan,

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Mr. Hollister's 2009 and 2010 target awards were set at amounts that exceed his contractual bonus amount. The employment agreement provides that Mr. Hollister also is entitled to participate in the LTIP and in such other benefit plans and programs as our general partner may provide for its employees in general. The agreement includes a confidentiality provision which, subject to typical exceptions for requirement of law and public knowledge (other than as a result of unauthorized disclosure by Mr. Hollister), will continue for two years following Mr. Hollister's termination of employment. The agreement also includes non-competition provisions which continue during the term of the agreement and for a period of two years thereafter. Also see "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Hollister's employment agreement, as amended, relating to termination, change of control and related payment obligations.

        Edward J. Faneuil is employed as Executive Vice President, General Counsel and Secretary pursuant to an employment agreement with our general partner. Mr. Faneuil's employment agreement became effective as of July 1, 2006 and continues through December 31, 2011 unless terminated earlier in accordance with the terms of the agreement. The agreement provides for an annual base salary of $358,050 for the 12-month period commencing July 1, 2006. Thereafter, Mr. Faneuil's base salary will be reviewed by the Compensation Committee at least annually. In 2010, Mr. Faneuil's base salary was $376,000. Mr. Faneuil also is entitled to receive bonuses in accordance with the then applicable short-term incentive plan as authorized by the Compensation Committee to be paid no later than March 15 of the calendar year immediately following the calendar year in which such bonuses are earned. Mr. Faneuil is eligible to participate in our general partner's health insurance, pension, 401(k) and other employee benefit plans and will also receive additional fringe benefits consistent with benefits previously provided to him under prior arrangements. Mr. Faneuil is eligible to participate in the LTIP on the same general basis as the other executive officers of our general partner. The agreement includes a confidentiality provision which, subject to typical exceptions for requirement of law and public knowledge (other than as a result of unauthorized disclosure by Mr. Faneuil), will continue for two years following Mr. Faneuil's termination of employment. The agreement also includes non-competition and non-solicitation provisions which continue during the term of the agreement and for a period of two years thereafter. Mr. Faneuil also has entered into a deferred compensation agreement with our general partner. See "—Deferred Compensation Agreement" below for a description of this non-qualified deferred compensation plan. Mr. Faneuil also has entered into a supplemental executive retirement plan ("SERP") agreement with our general partner to provide him with supplemental retirement benefits in consideration of past and future services provided by him and in recognition of his ineligibility to participate in our increased benefits program in connection with the freezing of benefits under the pension plan. See "—Supplemental Executive Retirement Plan Agreements" for a discussion of the provisions in Mr. Faneuil's SERP agreement. See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's employment agreement, as amended, and in his amended and restated deferred compensation agreement relating to termination, change of control and related payment obligations.

        Charles A. Rudinsky, Executive Vice President and Chief Accounting Officer, is an at will employee and does not have an employment agreement with our general partner. In 2010, Mr. Rudinsky's base salary was $273,000. Mr. Rudinsky also has entered into a supplemental executive retirement plan ("SERP") agreement with our general partner to provide him with supplemental retirement benefits in consideration of past and future services provided by him and in recognition of his ineligibility to participate in our increased benefits program in connection with the freezing of benefits under the pension plan. See "—Supplemental Executive Retirement Plan Agreements" for a discussion of the provisions in Mr. Rudinsky's SERP agreement.

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        On December 31, 2008, our general partner and Edward J. Faneuil entered into a deferred compensation agreement pursuant to which Mr. Faneuil will be subject to terms and conditions relating to confidential information, non-solicitation and non-competition, as provided therein. See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's deferred compensation agreement relating to termination, change of control and related payment obligations.

    Supplemental Executive Retirement Plan Agreements

        On December 31, 2009, our general partner entered into SERP agreements with each of Edward J. Faneuil and Charles A. Rudinsky. The value of the SERP benefits to be provided under the agreements, expressed as single lump sum payments, will be $159,355 for Mr. Faneuil and $277,318 for Mr. Rudinsky. Each of Messrs. Faneuil and Rudinsky will acquire a fully vested and nonforfeitable interest in his respective SERP benefit only to the extent he is continuously employed with our general partner from December 31, 2009 through the vesting dates set forth in his agreement, or if he dies or becomes Disabled (as such term is defined in the agreements) or if there is a Change in Control (as such term is defined in the agreements). See "Potential Payments Upon Termination or Change of Control" for a discussion of the provisions in Mr. Faneuil's and Mr. Rudinsky's SERP agreements relating to termination, change of control and related payment obligations.

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Potential Payments upon a Change of Control or Termination

        The following table shows potential payments to our named executive officers under existing contracts, agreements, plans or arrangements, whether written or unwritten, for various scenarios involving a change of control or termination of employment of each such named executive officer assuming a December 31, 2010 termination date.

 
   
   
   
  Termination by general
partner without Cause /
Constructive Termination /
Breach by general partner
   
 
Name
  Change in
Control
($)
  Death
($)
  Disability
($)
  No Change
in Control
($)
  With
a Change
In Control
($)
  Nonrenewal
($)
 

Eric Slifka(1)

                                     
 

Severance Amount

        3,200,000     3,200,000     3,200,000     4,800,000     800,000  
 

LTIP awards(5)

    1,812,154     3,372,802     3,372,802     1,245,104     3,372,802     724,867  
 

Fringe benefits

        42,538     42,538     42,538     42,538      
 

Life insurance benefits

        210,000                  
                           
 

Total

    1,812,154     6,825,340     6,615,340     4,487,642     8,215,340     1,524,867  

Thomas J. Hollister(2)

                                     
 

Severance Amount

                1,156,000     1,831,000      
 

LTIP awards(5)

    1,268,510     1,268,510     1,268,510     1,268,510     1,268,510      
 

Fringe benefits

                34,739     34,739      
 

Life insurance benefits

        210,000                  
                           
 

Total

    1,268,510     1,478,510     1,268,510     2,459,249     3,134,249      

Edward J. Faneuil(3)

                                     
 

Severance Amount

                752,000     1,027,000      
 

Deferred Compensation

    819,477     819,477     819,477              
 

SERP benefit

    159,355     159,355     159,355     31,871     31,871      
 

LTIP awards(5)

    996,702